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\ 











Office of Air Quality 
Ranning And Standards 
Research Triangle Ffcrk, NC 27711 


EPA-454/R-98-011 
•June 1998 


United States 
Environmental Protection 
Agency 


^ EPA 


LOCATING AND ESTIMATING 
AIR EMISSIONS FROM 





































































































Disclaimer 


This report has been reviewed by the Office of Air Quality Planning and Standards, U.S. 
Environmental Protection Agency, and has been approved for publication. Mention of trade 
names and commercial products does not constitute endorsement or recommendation of use. 


EPA-454/R-98-011 



v 


11 


TABLE OF CONTENTS 


Section 


Page 


LIST OF TABLES.x 

LIST OF FIGURES. xvi 

EXECUTIVE SUMMARY .xx 

1.0 PURPOSE OF DOCUMENT. 1-1 

2.0 OVERVIEW OF DOCUMENT CONTENTS . 2-1 

3.0 BACKGROUND INFORMATION.. 3-1 

3.1 NATURE OF POLLUTANT. 3-1 

3.2 OVERVIEW OF PRODUCTION AND USE. 3-4 

3.3 OVERVIEW OF EMISSIONS . 3-8 

4.0 EMISSIONS FROM BENZENE PRODUCTION. 4-1 

4.1 CATALYTIC REFORMING/SEPARATION PROCESS. 4-7 

4.1.1 Process Description for Catalytic Reforming/Separation. 4-7 

4.1.2 Benzene Emissions from Catalytic Reforming/Separation. 4-9 

4.2 TOLUENE DEALKYLATION AND TOLUENE 

DISPROPORTIONATION PROCESS . 4-11 

4.2.1 Toluene Dealkylation . 4-12 

4.2.2 Toluene Disproportionation . 4-13 

4.3 ETHYLENE PRODUCTION. 4-16 

4.3.1 Process Description . 4-16 

4.3.2 Benzene Emissions from Ethylene Plants and Benzene Recovery 

from Pyrolysis Gasoline. 4-32 


4.4 COKE OVEN AND COKE BY-PRODUCT RECOVERY PLANTS . . . 4-36 


4.4.1 Process Description . 4-36 

4.4.2 Benzene Emissions. 4-46 


Cj^lWS% 


111 

























TABLE OF CONTENTS, continued 


Section Page 


4.5 METHODS FOR ESTIMATING BENZENE EMISSIONS FROM 

EMISSION SOURCES...’. 4-61 

4.5.1 Process Vent Emissions, Controls, and Regulations. 4-62 

4.5.2 Equipment Leak Emissions, Controls, and Regulations . 4-70 

4.5.3 Storage Tank Emissions, Controls, and Regulations. 4-77 

4.5.4 Wastewater Collection and Treatment System Emissions, 

Controls, and Regulations . 4-82 

4.5.5 Product Loading and Transport Operations Emissions, Controls, 

and Regulations. 4-85 

5.0 EMISSIONS FROM MAJOR USES OF BENZENE. 5-1 

5.1 ETHYLBENZENE AND STYRENE PRODUCTION. 5-2 

5.1.1 Process Description for Ethylbenzene and Styrene Production 

Using Benzene Alkylation and Ethylbenzene Dehydrogenation .... 5-3 

5.1.2 Process Description for Ethylbenzene Production from Mixed 

Xylenes . 5-9 

5.1.3 Process Description for Styrene Production from Ethylbenzene 

Hydroperoxidation. 5-10 

5.1.4 Process Description for Styrene Production by an Isothermal 

Process. 5-12 

5.1.5 Benzene Emissions from Ethylbenzene and Styrene Production 

via Alkylation and Dehydrogenation. 5-14 

5.1.6 Control Technology for Ethylbenzene/Styrene Processes . 5-19 

5.2 CYCLOHEXANE PRODUCTION. 5-20 

5.2.1 Process Description for Cyclohexane Production via Benzene 

Hydrogenation... 5-21 

5.2.2 Benzene Emissions from Cyclohexane Production via Benzene 

Hydrogenation. 5-23 

5.2.3 Process Description for Cyclohexane Production via Separation 

of Petroleum Fractions . 5-24 

5.2.4 Benzene Emissions from Cyclohexane Production via Separation 

of Petroleum Fractions . 5-26 

5.3 CUMENE PRODUCTION . 5_26 

5.3.1 Process Descriptions for Cumene Production by Alkylating 

Benzene with Propylene. 5_27 

5.3.2 Benzene Emissions From Cumene Production . 5-34 


IV 
























TABLE OF CONTENTS, continued 


Section Page 

5.4 PHENOL PRODUCTION. 5-35 

5.4.1 Phenol Production Techniques .. 5-39 

5.4.2 Benzene Emissions from Phenol Production. 5-47 

5.5 NITROBENZENE PRODUCTION. 5-49 

5.5.1 Process Descriptions for Continuous Nitration.. 5-49 

5.5.2 Benzene Emissions from Nitrobenzene Production .'. 5-53 

5.6 ANILINE PRODUCTION. 5-58 

5.6.1 Process Descriptions for Aniline Production for Nitrobenzene ... 5-58 

5.6.2 Benzene Emissions from Aniline Production . 5-61 

5.7 CHLOROBENZENE PRODUCTION. 5-62 

5.7.1 Process Description for Chlorobenzene Production by Direct 

Chlorination of Benzene. 5-62 

5.7.2 Benzene Emissions from Chlorobenzene Production . 5-67 

5.8 LINEAR ALKYLBENZENE PRODUCTION. 5-70 

5.8.1 Process Description for Production of LAB Using the Olefin 

Process .. 5-70 

5.8.2 Benzene Emissions from LAB Production Using the Olefm 

Process. 5-74 

5.8.3 Process Description for Production of LAB Using the 

Chlorination Process. 5-74 

5.8.4 Benzene Emissions from LAB Production Using the Chlorination 

Process. 5-78 

5.9 OTHER ORGANIC CHEMICAL PRODUCTION. 5-80 

5.9.1 Hvdroquinone . 5-80 

5.9.2 Benzophenone. 5-81 

5.9.3 Benzene Sulfonic Acid. 5-81 

5.9.4 Resorcinol . 5-81 

5.9.5 Biphenyl. 5-82 

5.9.6 Anthraquinone. 5-82 

5.10 BENZENE USE AS A SOLVENT .:. 5-82 

6.0 EMISSIONS FROM OTHER SOURCES. 6-1 

6.1 OIL AND GAS WELLHEADS. 6-1 


v 






























TABLE OF CONTENTS, continued 

Section Esge 


6.1.1 Description of Oil and Gas Wellheads. 6-1 

6.1.2 Benzene Emissions from Oil and Gas Wellheads. 6-2 

6.2 GLYCOL DEHYDRATION UNITS. 6-4 

6.2.1 Process Description for Glycol Dehydration Units. 6-5 

6.2.2 Benzene Emissions from Glycol Dehydration Units ........... 6-8 

6.2.3 Controls and Regulatory Analysis . 6-13 

6.3 PETROLEUM REFINERY PROCESSES. 6-14 

6.3.1 Description of Petroleum Refineries. 6-14 

6.3.2 Benzene Emissions from Petroleum Refinery Processes and 

Operations . 6-17 

6.3.3 Controls and Regulatory Analysis . 6-28 

6.4 GASOLINE MARKETING. 6-31 

6.4.1 Benzene Emissions from Loading Marine Vessels. 6-34 

6.4.2 Benzene Emissions from Bulk Gasoline Plants and Bulk Gasoline 

Terminals. 6-37 

6.4.3 Benzene Emissions from Service Stations . 6-46 

6.4.4 Control Technology for Marine Vessel Loading. 6-49 

6.4.5 Control Technology for Gasoline Transfer. 6-53 

6.4.6 Control Technology for Gasoline Storage . 6-53 

6.4.7 Control Technology for Vehicle Refueling Emissions .. 6-56 

6.4.8 Regulatory Analysis . 6-58 

6.5 PUBLICLY OWNED TREATMENT WORKS . 6-59 

6.5.1 Process Description of POTWs. 6-59 

6.5.2 Benzene Emissions From POTWs ... 6-68 

6.5.3 Control Technologies for POTWs . 6-69 

6.5.4 Regulatory Analysis . 6-72 

6.6 MUNICIPAL SOLID WASTE LANDFILLS. 6-72 

6 .6.1 Process Description of MSW Landfills. 6-73 

6.6.2 Benzene Emissions from MSW Landfills. 6-74 

6.6.3 Control Technologies for MSW Landfills . 6-80 

6.6.4 Regulatory Analysis . 6-81 

6.7 PULP, PAPER, AND PAPERBOARD INDUSTRY. 6-81 

6.7.1 Process Description for Pulp, Paper, and Paperboard Making 

Processes . 6 _g 2 

6.7.2 Benzene Emissions from Pulp, Paper and Papermaking Processes 6-91 

vi 



































TABLE OF CONTENTS, continued 


Section Page 

6.8 SYNTHETIC GRAPHITE MANUFACTURING. 6-93 

6.8.1 Process Description for Synthetic Graphite Production. 6-94 

6.8.2 Benzene Emissions from Synthetic Graphite Production. 6-97 

6.8.3 Control Technologies for Synthetic Graphite Production. 6-99 

6.9 CARBON BLACK MANUFACTURE. 6-99 

6.9.1 Process Description for Carbon Black Manufacture.6-101 

6.9.2 Benzene Emissions from Carbon Black Manufacture.6-104 

6 .10 RAYON-BASED CARBON FIBER MANUFACTURE.6-105 

6.10.1 Process Description for the Rayon-Based Carbon Fiber 

Manufacturing Industry.6-106 

6.10.2 Benzene Emissions from the Rayon-Based Carbon Fiber 

Manufacturing Industry.6-107 

6.10.3 Controls and Regulatory Analysis .6-107 

6.11 ALUMINUM CASTING . . ..6-107 

6.11.1 Process Description for Aluminum Casting Facilities.6-107 

6.11.2 Benzene Emissions From Aluminum Metal Casting.6-111 

6.11.3 Control Technologies for Aluminum Casting Operations .6-112 

6.12 ASPHALT ROOFING MANUFACTURING.6-112 

6.12.1 Process Description .6-114 

6.12.2 Benzene Emissions from Asphalt Roofmg Manufacture .6-127 

6.13 CONSUMER PRODUCTS/BUILDING SUPPLIES .6-129 

7.0 EMISSIONS FROM COMBUSTION SOURCES. 7-1 

7.1 MEDICAL WASTE INCINERATORS. 7-1 

7.1.1 Process Description: Medical Waste Incinerators. 7-2 

7.1.2 Benzene Emissions From Medical Waste Incinerators . 7-7 

7.1.3 Control Technologies for Medical Waste Incinerators . 7-7 

7.1.4 Regulatory Analysis . 7-9 

7.2 SEWAGE SLUDGE INCINERATORS . 7-10 

7.2.1 Process Description: Sewage Sludge Incinerators. 7-11 

7.2.2 Benzene Emissions from Sewage Sludge Incineration. 7-19 

7.2.3 Control Technologies for Sewage Sludge Incinerators . 7-19 

7.2.4 Regulatory Analysis . 7-25 


Vll 


































TABLE OF CONTENTS, continued 


Section Page 


7.3 HAZARDOUS WASTE INCINERATION. 7-25 

7.3.1 Process Description: Incineration 7-26 

7.3.2 Industrial Kilns, Boilers, and Furnaces. 7-36 

7.3.3 Benzene Emissions From Hazardous Waste Incineration. 7-37 

7.3.4 Control Technologies for Hazardous Waste Incineration. 7-37 

7.3.5 Regulatory Analysis . 7-39 

7.4 EXTERNAL COMBUSTION OF SOLID, LIQUID, AND GASEOUS 

FUELS IN STATIONARY SOURCES FOR HEAT AND POWER 
GENERATION. 7-40 

7.4.1 Utility Sector. 7-40 

7.4.2 Industrial/Commercial Sector. 7-51 

7.4.3 Residential Sector. 7-59 

7.5 STATIONARY INTERNAL COMBUSTION . 7-67 

7.5.1 Reciprocating Engines. 7-67 

7.5.2 Gas Turbines. 7-74 

7.6 SECONDARY LEAD SMELTING. 7-79 

7.6.1 Process Description . 7-79 

7.6.2 Benzene Emissions From Secondary Lead Smelters. 7-91 

7.6.3 Control Technologies for Secondary Lead Smelters. 7-95 

7.7 IRON AND STEEL FOUNDRIES . 7-95 

7.7.1 Process Description for Iron and Steel Foundries . 7-97 

7.7.2 Benzene Emissions From Iron and Steel Foundries .7-100 

7.7.3 Control Technologies for Iron and Steel Foundries .7-102 

7 8 POPTLAND CEMENT PRODUCTION.7-IQ? 

7.8.1 Process Description for the Portland Cement Industry .7-104 

7.8.2 Benzene Emissions from the Portland Cement Industry and 

Regulatory Analysis .7-107 

7.9 HOT-MIX ASPHALT PRODUCTION. 7 _ 110 

7.9.1 Process Description .7-110 

7.9.2 Benzene Emissions from the Hot-Mix Asphalt Production.7-119 

7.10 OPEN BURNING OF BIOMASS, SCRAP TIRES, AND 

AGRICULTURAL PLASTIC FILM . 7 _ 121 

7.10.1 Biomass Burning . 7-121 

7.10.2 Tire Burning. 7-125 

7.10.3 Agricultural Plastic Film Burning .7-129 

viii 



































TABLE OF CONTENTS, continued 


Section Page 

8.0 BENZENE EMISSIONS FROM MOBILE SOURCES . 8-1 

8.1 ON-ROAD MOBILE SOURCES. 8-2 

8.2 OFF-ROAD MOBILE SOURCES. 8-5 

8.3 MARINE VESSELS. 8-10 

8.4 LOCOMOTIVES. 8-13 

8.5 AIRCRAFT . 8-14 

8.6 ROCKET ENGINES . 8-15 

9.0 SOURCE TEST PROCEDURES . 9-1 

9.1 EPA METHOD 0030 . 9-2 

9.2 EPA METHODS 5040/5041 . 9-4 

9.3 EPA METHOD 18. 9-5 

9.4 EPA METHOD TO-1. 9-8 

9.5 EPA METHOD TO-2. 9-9 

9.6 EPA METHOD TO-14. 9-14 

9.7 FEDERAL TEST PROCEDURE (FTP). 9-16 

9.8 AUTO/OIL AIR QUALITY IMPROVEMENT RESEARCH 

PROGRAM SPECIATION METHOD. 9-18 

10.0 REFERENCES. 10-1 

APPENDICES 

Appendix A Summary of Emission Factors 

Appendix B United States Petroleum Refineries: Location by State 


IX 
















































' 

' 


































. 




















■ 






' 


■ 
















































LIST OF TABLES 


Table Page 

3-1 Chemical Identification of Benzene. 3-2 

3- 2 Physical and Chemical Properties of Benzene . 3-3 

4- 1 Benzene Production Facilities. 4-2 

4-2 Ethylene Producers - Location and Capacity. 4-17 

4-3 Stream Designations for Figure 4-5, Production of Ethylene from Naphtha 

and/or Gas-oil Feeds . 4-24 

4-4 Benzene Emission Factors for a Hypothetical Ethylene Plant . 4-33 

4-5 Coke Oven Batteries Currently Operating in the United States. 4-38 

4-6 Summary of Benzene Emission Factors for Furnace and Foundry Coke 

By-product Recovery Plants. 4-51 

4-7 Summary of Benzene Emission Factors for Equipment Leaks at Furnace Coke 

By-product Recovery Plants. 4-54 

4-8 Summary of Benzene Emission Factors for Equipment Leaks at Foundry Coke 

By-product Recovery Plants . 4-56 

4-9 Techniques to Control Benzene Emissions from Equipment Leaks Required by 

the Benzene NESHAP for Coke By-product Control Recovery Plants. 4-61 

4-10 Control Technologies that Form the Basis of Air Pollution Control Standards .. 4-63 

4-11 Other Control Technologies that Can be Used to Meet Standards. 4-64 

4-12 Comparison of VOC Control Technologies. 4-68 

4-13 SOCMI Average Total Organic Compound Emission Factors for Equipment 

Leak Emissions.,. 4-72 

4-14 Refinery Average Emission Factors. 4-73 

4-15 Marketing Terminal Average Emission Factors . 4-74 

4-16 Oil and Gas Production Operations Average Emission Factors . 4-75 


x 




















LIST OF TABLES, continued 


Table Page 

4-17 SOCMI Screening Value Range Total Organic Compound Emission Factors for 

Equipment Leak Emissions . 4-76 

4-18 Refinery Screening Ranges Emission Factors. 4-77 

4-19 Marketing Terminal Screening Ranges Emission Factors. 4-78 

4-20 Oil and Gas Production Operations Screening Ranges Emission Factors . 4-79 

4- 21 Control Techniques and Efficiencies Applicable to Equipment Leak Emissions . . 4-80 

5- 1 U.S. Producers of Ethylbenzene and Styrene. 5-4 

5-2 Emission Factors for Ethylbenzene/Styrene Production via Alkylation and 

Dehydrogenation. 5-15 

5-3 U.S. Producers of Cyclohexane . 5-21 

5-4 U.S. Producers of Cumene . 5-27 

5-5 Summary of Emission Factors for Cumene Production at One Facility Using the 

Aluminum Chloride Catalyst . 5-36 

5-6 U.S. Producers of Phenol . 5.37 

5-7 Summary of Emission Factors for Phenol Production by the Peroxidation of 

Cumene...;. 5 _ 4 g 

5-8 U.S. Producers of Nitrobenzene. 5_50 

5-9 Summary of Emission Factors for Hypothetical Nitrobenzene Production Plants . 5-54 

5-10 U.S. Producers of Aniline. 5.59 

5-11 U.S. Producers of Mono-, Di-, and Trichlorobenzene. 5-63 

5-12 Emission Factors for Chlorobenzene Production by Direct Chlorination of 

Benzene. ^ 

5-13 U.S. Producers of Linear Alkylbenzene (Detergent Alkylates) . 5.71 


xi 




















LIST OF TABLES, continued 




Table Page 

5-14 Summary of Emission Factors for Hypothetical Linear Alkylbenzene Plant 

Using the Olefin Process. 5-75 

5-15 Summary of Emission Factors for Hypothetical Linear Alkylbenzene Plant 

Using the Chlorination Process. 5-79 

5-16 Partial List of Manufacturers in Source Categories where Benzene Is Used as a 

Solvent . 5-84 

5-17 U.S. Producers of Ethanol or Isopropanol. 5-86 

5-18 U.S. Producers of Caprolactam . 5-89 

5- 19 Summary of Emission Factors for Benzene Use as a Solvent. 5-90 

6- 1 Benzene and Total Hydrocarbons Equipment Leak Emission Factors for Oil 

Wellhead Assemblies . 6-3 

6-2 Glycol Dehydration Unit Population Data. 6-6 

6-3 Reactive Organic Compounds (ROCs) and BTEX Emission Factors for Glycol 

Dehydration Units. 6-9 

6-4 Glycol Dehydration Emission Program Inputs and Outputs. 6-12 

6-5 Potential Sources of Benzene Emissions at Petroleum Refineries. 6-18 

6-6 Concentration of Benzene in Refinery Process Unit Streams. 6-19 

6-7 Concentration of Benzene m Refinery Products . 6-20 

6-8 Median Component Counts for Process Units from Small Refineries . 6-22 

6-9 Median Component Counts for Process Units from Large Refineries . 6-23 

6-10 Model Process Unit Characteristics for Petroleum Refinery Wastewater. 6-25 

6-11 Wastewater Emission Factors for Petroleum Refineries. 6-27 

6-12 Uncontrolled Volatile Organic Compound and Benzene Emission Factors for 


Loading, Ballasting, and Transit Losses from Marine Vessels. 6-35 


Xll 






















LIST OF TABLES, continued 


Table Page 

6-13 Uncontrolled Total Organic Compound Emission Factors for Petroleum Marine 

Vessel Sources ... 6-36 

6-14 Benzene Emission Factors for Gasoline Loading Racks at Bulk Terminals and 

Bulk Plants.. 6-38 

6-15 Benzene Emission Factors for Storage Losses at a Typical Gasoline Bulk 

Terminal . 6-41 

6-16 Gasoline Vapor and Benzene Emission Factors for a Typical Bulk Plant. 6-43 

6-17 Benzene Emission Factors for Storage Losses at a Typical Pipeline Breakout Station 6-44 

6-18 Gasoline Vapor and Benzene Emission Factors for a Typical Service Station ... 6-48 

6-19 RVP Limits by Geographic Location. 6-50 

6-20 Seasonal Variation for Temperature Difference between Dispensed Fuel and 

Vehicle Fuel Tank. 6-52 

6-21 Monthly Average Dispensed Liquid Temperature. 6-52 

6-22 Summary of Benzene Emission Factors for POTWs . 6-70 

6-23 Summary of Uncontrolled Emission Concentrations of Benzene from Landfills . . 6-77 

6-24 Controlled Benzene Emission Factor for Landfills . 6-81 

6-25 Distribution of Kraft Pulp Mills in the United States (1993) . 6-83 

6-26 List of Common Potential Emission Points within the Kraft Pulp and 

Papermaking Process . 6 _g 4 

6-27 Emission Factors for Synthetic Graphite Production. 6-98 

6-28 Locations and Annual Capacities of Carbon Black Producers in 1994 . 6-100 

6-29 Stream Codes for the Oil-Furnace Process Illustrated in Figure 6-10 .6-103 

6-30 Typical Operating Conditions for Carbon Black Manufacture (High Abrasion 

Furnace ) .6-105 


Xlll 



















LIST OF TABLES, continued 


Table Page 

6-31 Emission Factor for Carbon Black Manufacture.6-105 

6-32 Rayon-based Carbon Fiber Manufacturers.6-106 

6-33 Emission Factor for Rayon-based Carbon Manufacture.6-108 

6-34 Emission Factors for Aluminum Casting.6-113 

6-35 Asphalt Roofmg Manufacturers .6-115 

6- 36 Emission Factor for Asphalt Roofmg Manufacture.6-128 

7- 1 Emission Factor for Medical Waste Incineration. 7-8 

7-2 Summary of Emission Factors for Sewage Sludge Incineration . 7-20 

7-3 Summary of Emission Factors for One Sewage Sludge Incineration Facility 

Utilizing a Multiple Hearth Furnace. 7-21 

7-4 Summary of Benzene Emission Factors for Hazardous Waste Incineration. 7-38 

7-5 Summary of Benzene Emission Factors for Utility Boilers. 7-50 

7-6 Summary of Benzene Emission Factors for Industrial and 

Commercial/Institutional Boilers. 7-57 

7-7 Summary of Benzene Emission Factors for Residential Woodstoves. 7-66 

7-8 Summary of Benzene Emission Factors for Reciprocating Engines. 7-73 

7-9 Summary of Benzene Emission Factors for Gas Turbines. 7-77 

7-10 U.S. Secondary Lead Smelters. 7-80 

7-11 Summary of Benzene Emission Factors for Secondary Lead Smelting. 7-94 

7-12 Benzene Emission Factor for Iron Foundries.7-101 

7-13 Summary of Portland Cement Plant Capacity Information .7-105 

7-14 Summary of Emission Factors for the Portland Cement Industry.7-109 


xiv 
























LIST OF TABLES, continued 

Table Page 

7-15 Emission Factors for Hot-Mix Asphalt Manufacture.,.7-120 

7-16 Summary of Benzene Emission Factors for Biomass Burning .7-124 

7-17 Summary of Benzene Emission Factors for Biomass Burning by Fuel Type .... 7-126 

7-18 Summary of Benzene Emission Factors for Open Burning of Tires.7-128 

7- 19 Summary - of Benzene Emission Factors for Open Burning of Agricultural Plastic 

Film.7-130 

8- 1 Benzene Emission Factors for 1990 Taking into Consideration Vehicle Aging ... 8-4 

8-2 Off-road Equipment Types and Hydrocarbon Emission Factors Included in the 

NEVES. 8-6 

8-3 Weight Percent Factors for Benzene . . . 8-11 

8-4 Benzene Emission Factors for Commercial Marine Vessels . 8-12 

8-5 Benzene Emission Factors for Locomotives. 8-13 

8-6 Benzene Content in Aircraft Landing and Takeoff Emissions . 8-14 

8-7 Emission Factors for Rocket Engines. 8-16 


xv 














LIST OF FIGURES 


Figure Pa ge 

3- 1 Production and Use Tree for Benzene . 3-7 

4- 1 Universal Oil Products Platforming (Reforming) Process. 4-8 

4-2 Flow Diagram of a Glycol BTX Unit Process . 4-10 

4-3 Process Flow Diagram of a Toluene Dealkylation Unit . 4-14 

4-4 Toluene Disproportionation Process Flow Diagram (Tatory Process). 4-15 

4-5 Process Flow Diagram for Ethylene Production from Naphtha and/or Gas-Oil 

Feeds . 4-22 

4-6 Production of BTX by Hydrogenation of Pyrolysis Gasoline. 4-31 

» 

4-7 Coke Oven By-Product Recovery, Representative Plant. 4-41 

4- 8 Litol Process Flow Diagram. 4-45 

5- 1 Basic Operations that May be used in the Production of Ethylbenzene by 

Benzene Alkylation with Ethylene. 5-6 

5-2 Basic Operations that May be used in the Production of Styrene by Ethylbenzene 

Dehydrogenation. 5-8 

5-3 Ethylbenzene Hydroperoxidation Process Block Diagram. 5-11 

5-4 Isothermal Processing of Styrene. 5-13 

5-5 Process Flow Diagram for Cyclohexane Production using the Benzene 

Hydrogenation Process. 5-22 

5-6 Process Flow Diagram for Cyclohexane from Petroleum Fractions. 5-25 

5-7 Process for the Manufacture of Cumene Using Solid Phosphoric Acid Catalyst . . 5-29 

5-8 Process for the Manufacture of Cumene Using Aluminum Chloride Catalyst ... 5-31 

5-9 Flow Diagram for Phenol Production from Cumene Using the Allied Process . . 5-40 

5-10 Flow Diagram for Phenol Production Using the Hercules Process. 5-44 


xvi 




















LIST OF FIGURES, continued 


Figure Page 

5-11 Process Flow Diagram for Manufacture of Nitrobenzene. 5-51 

5-12 Flow Diagram for Manufacture of Aniline . 5-60 

- 5-13 Monochlorobenzene Continuous Production Process Diagram.. 5-64 

5-14 Dichlorobenzene and Trichlorobenzene Continuous Production Diagram. 5-66 

5-15 Linear Alkylbenzene Production Using the Olefm Process. 5-73 

5- 16 Production of Linear Alkylbenzenes Via Chlorination. 5-76 

6- 1 Flow Diagram for Glycol Dehydration Unit . 6-7 

6-2 Process Flow Diagram for a Model Petroleum Refinery . . . . ; . 6-16 

6-3 The Gasoline Marketing Distribution System in the United States . 6-32 

6-4 Bulk Plant Vapor Balance System (Stage I). 6-54 

6-5 Service Station Vapor Balance System. 6-55 

6-6 Process Flow Diagram for a Typical POTW. 6-61 

6-7 Typical Kraft Pulp-Making Process with Chemical Recovery . 6-85 

6-8 Typical Down-flow Bleach Tower and Washer . 6-92 

6-9 Process Flow Diagram for Manufacture of Synthetic Graphite a . 6-95 

6-10 Process Flow Diagram for an Oil-furnace Carbon Black Plant.6-102 

6-11 Flow Diagram of a Typical Aluminum Casting Facility.6-109 

6-12 Asphalt Blowing Process Flow Diagram.6-119 

6-13 Asphalt-Saturated Felt Manufacturing Process.6-122 

6-14 Organic Shingle and Roll Manufacturing Process Flow Diagram. 6-123 


XVII 
























LIST OF FIGURES, continued 


Figure Page 

7-1 Controlled-Air Incinerator. 7-3 

7-2 Excess-Air Incinerator . 7-5 

7-3 Cross Section of a Multiple Hearth Furnace . 7-12 

7-4 Cross Section of a Fluidized Bed Furnace. 7-14 

7-5 Cross Section of an Electric Infrared Furnace . 7-17 

7-6 Venturi/Impingement Tray Scrubber . 7-23 

7-7 General Orientation of Hazardous Waste Incineration Subsystems and Typical 

Component Options . 7-27 

7-8 Typical Liquid Injection Combustion Chamber . 7-30 

7-9 Typical Rotary Kiln/Afterburner Combustion Chamber. 7-32 

7-10 Typical Fixed Hearth Combustion Chamber . 7-33 

7-11 Simplified Boiler Schmatic. 7-42 

7-12 Single Wall-fired Boiler . 7-44 

7-13 Cyclone Burner. 7-46 

7-14 Simplified Atmospheric Fluidized Bed Combustor Process Flow Diagram. 7-47 

7-15 Spreader Type Stoker-fired Boiler - Continuous Ash Discharge Grate. 7-48 

7-16 Basic Operation of Reciprocating Internal Combustion Engines. 7-69 

7-17 Gas Turbine Engine Configuration . 7-75 

7-18 Simplified Process Flow Diagram for Secondary Lead Smelting . 7-81 

7-19 Cross-sectional View of a Typical Stationary Reverberatory Furnace. 7-84 

* 

7-20 Cross Section of a Typical Blast Furnace . 7-86 


xvm 























LIST OF FIGURES, continued 


Fi gure Page 

7-21 Side-View of a Typical Rotary Reverbatory Furnace. 7-89 

7-22 Cross-sectional View of an Electric Furnace for Processing Slag. 7-92 

7-23 Process Flow Diagram for a Typical Sand-Cast Iron and Steel Foundry . 7-98 

7-24 Emission Points in a Typical Iron Foundry and Steel Foundry. 7-99 

7-25 Process Diagram of Portland Cement Manufacture by Dry Process with 

Preheater.7-108 

7-26 General Process Flow Diagram for Batch Mix Asphalt Paving Plants.7-113 

7-27 General Process Flow Diagram for Drum Mix Asphalt Paving Plants.7-116 

7-28 General Process Flow Diagram for Counter Flow Drum Mix Asphalt Paving 

Plants .7-117 

9-1 Volatile Organic Sampling Train (VOST). 9-3 

9-2 Trap Desorption/Analysis Using EPA Methods 5040/5041 . 9-6 

9-3 Integrated Bag Sampling Train. 9-7 

9-4 Block Diagram of Analytical System for EPA Method TO-1. 9-10 

9-5 Typical Tenax® Cartridge . 9-11 

9-6 Carbon Molecular Sieve Trap (CMS) Construction. 9-12 

9-7 GC/MS Analysis System for CMS Cartridges . 9-13 

9-8 Sampler Configuration for EPA Method TO-14. 9-15 

9-9 Vehicle Exhaust Gas Sampling System. 9_17 


xix 





















EXECUTIVE SUMMARY 


The 1990 Clean Air Act Amendments contain a list of 188 hazardous air 
pollutants (HAPs) which the U.S. Environmental Protection Agency must study, identify 
sources of, and determine if regulations are warranted. One of these HAPs, benzene, is the 
subject of this document. This document describes the properties of benzene as an air 
pollutant, defmes its production and use patterns, identifies source categories of air emissions, 
and provides benzene emission factors. The document is a part of an ongoing EPA series 
designed to assist the general public at large, but primarily State/local air agencies, in 
identifying sources of HAPs and developing emissions estimates. 

Benzene is primarily used in the manufacture of other organic chemicals, 
including ethylbenzene/styrene, cumene/phenol, cyclohexane, and nitrobenzene/aniline. 
Benzene is emitted into the atmosphere from its production, its use as a chemical feedstock in 
the production of other chemicals, the use of those other chemicals, and from fossil fuel and 
biomass combustion. Benzene is also emitted from a wide variety of miscellaneous sources 
including oil and gas wellheads, glycol dehydrators, petroleum refining, gasoline marketing, 
wastewater treatment, landfills, pulp and paper mills, and from mobile sources. 

In addition to identifying sources of benzene emissions, information is provided 
that specifies how’ individual sources of benzene may be tested to quantify- air emissions. 


xx 












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SECTION 1.0 

PURPOSE OF DOCUMENT 


The U.S. Environmental Protection Agency (EPA), State, and local air pollution 
control agencies are becoming increasingly aware of the presence of substances in the ambient 
air that may be toxic at certain concentrations. This awareness, in turn, has led to attempts to 
identify source/receptor relationships for these substances and to develop control programs to 
regulate emissions. Unfortunately, limited information is available on the ambient air 
concentrations of these substances or about the sources that may be discharging them to the 
atmosphere. 


To assist groups interested in inventorying air emissions of various potentially 
toxic substances, EPA is preparing a series of locating and estimating (L&E) documents such 
as this one that compiles available information on sources and emissions of these substances. 
Other documents in the series are listed below: 


Substance 

Acrylonitrile 

Arsenic 

Butadiene 

Cadmium 

Carbon Tetrachloride 
Chlorobenzene (update) 
Chloroform 

Chromium (supplement) 
Chromium 


EPA Publication Number 

EPA-450/4-84-007a 

(Document under revision) 

EPA-454/R-96-008 

EPA-454/R-93-040 

EPA-450/4-84-007b 

EPA-454/R-93-044 

EPA-450/4-84-007c 

EPA-450/2-89-002 

EPA-450/4-84-007g 


1-1 




Substance 

F.PA Publication Nun 

Coal and Oil Combustion Sources 

EPA-450/2-89-001 

Cyanide Compounds 

EPA-454/R-93-041 

Dioxins and Furans 

EPA-454/R-97-003 

Epichlorohydrin 

EPA-450/4-84-007j 

Ethylene Dichloride 

EPA-450/4-84-007d 

Ethylene Oxide 

EPA-450/4-84-0071 

Formaldehyde 

EPA-450/4-91-012 

Lead 

EPA-454/R-98-006 

Manganese 

EPA-450/4-84-007h 

Medical Waste Incinerators 

EPA-454/R-93-053 

Mercury and Mercury Compounds 
(under revision) 

EPA-453/R-93-023 

Methyl Chloroform 

EPA-454/R-93-045 

Methyl Ethyl Ketone 

EP A-454/R-93-046 

Methylene Chloride 

EPA-454/R-93-006 

Municipal Waste Combustors 

EPA-450/2-89-006 

Nickel 

EPA-450/4-84-007f 

Perchloroethylene and 
Trichloroethylene 

EP A-450/2-89-013 

Phosgene 

EP A-450/4-84-007i 

Polychlorinated Biphenyls (PCBs) 

EPA-450/4-84-007n 

Polycyclic Organic Matter (POM) 

EPA-450/4-84-007p 

Sewage Sludge Incinerators 

EPA-450/2-90-009 

Styrene 

EPA-454/R-93-011 

Toluene • 

EPA-454/R-93-047 

Vinylidene Chloride 

EPA-450/4-84-007k 

Xylenes 

EPA-454/R-93-048 


This document deals specifically with benzene. Its intended audience includes 
Federal, State, and local air pollution personnel and others who are interested in locating 
potential emitters of benzene and estimating their air emissions. 


1-2 




Because of the limited availability of data on potential sources of benzene 
emissions and the variability in process configurations, control equipment, and operating 
procedure among facilities, this document is best used as a primer on (1) types of sources that 
may emit benzene, (2) process variations and release points that may be expected, and 
(3) available emissions information on the potential for benzene releases into the air. The 
reader is cautioned against using the emissions information in this document to develop an 
' exact assessment of emissions from any particular facility. 

Emission estimates may need to be adjusted to take into consideration 
participation in EPA’s voluntary emission reduction program or compliance with State or local 
regulations. 

It is possible, in some cases, that orders-of-magnitude differences may result 
between actual and estimated emissions, depending on differences in source configurations, 
control equipment, and operating practices. Thus, in all situations where an accurate 
assessment of benzene emissions is necessary, the source-specific information should be 
obtained to confirm the existence of particular emitting operations and the types and 
effectiveness of control measures, and to determine the impact of operating practices. A 
source test and/or material balance calculation should be considered as better methods of 
determining air emissions from a specific operation. 

In addition to the information presented in this document, another potential 
source of emissions data for benzene from facilities is the Toxic Chemical Release Inventory 
(TRI) form required by Title III, Section 313 of the 1986 Superfund Amendments and 
Reauthorization Act (SARA). 1 Section 313 requires owners and operators of facilities in 
certain Standard Industrial Classification Codes that manufacture, import, process, or 
otherwise use toxic chemicals (as listed in Section 313) to report annually their releases of 
these chemicals to all environmental media. As part of SARA 313, EPA provides public 
access to the annual emissions data. 


1-3 


The TRI data include general facility information, chemical information, and 
emissions data. Air emissions data are reported as total facility release estimates for fugitive 
emissions and point source emissions. No individual process or stack data are provided to 
EPA under the program. SARA Section 313 requires sources to use available stack monitoring 
data for reporting but does not require facilities to perform stack monitoring or other types of 
emissions measurement. If monitoring data are unavailable, emissions are to be quantified 
' based on best estimates of releases to the environment. 

The reader is cautioned that TRI will not likely provide facility, emissions, and 
chemical release data sufficient for conducting detailed exposure modeling and risk assessment. 
In many cases, the TRI data are based on annual estimates of emissions (i.e., on emission 
factors, material balance calculations, and engineering judgment). The EPA recommends use 
of TRI data in conjunction with the information provided in this document to locate potential 
emitters of benzene and to make preliminary estimates of air emissions from these facilities. 

For mobile sources, more data are becoming available for on-road vehicles. 
Additionally, the EPA model that generates emission factors undergoes regular update. The 
on-road mobile sources section in this document should therefore be viewed as an example of 
how emissions can be determined and the reader should look for more detailed data for the 
most accurate estimates. 

Data on off-road vehicles and other stationary sources remain unavailable. 
However, with EPA’s increased emphasis on air toxics, more benzene data are likely to be 
generated in the future. 

As standard procedure, L&E documents are sent to government, industry, and 
environmental groups wherever EPA is aware of expertise. These groups are given the 
opportunity to review a document, comment, and provide additional data where applicable. 
Where necessary, the document is then revised to incorporate these comments. Although this 
document has undergone extensive review, there may still be shortcomings. Comments 


1-4 


subsequent to publication are welcome and will be addressed based on available time and 
resources. In addition, any information on process descriptions, operating parameters, control 
measures, and emissions information that would enable EPA to improve on the contents of this 
document is welcome. All comments should be sent to: 


Group Leader 

Emission Factor and Inventory Group (MD-14) 
Office of Air Quality Planning and Standards 
U. S. Environmental Protection Agency 
Research Triangle Park, North Carolina 27711 


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SECTION 2.0 

OVERVIEW OF DOCUMENT CONTENTS 


This section briefly outlines the nature, extent, and format of the material 
presented in the remaining sections of this report. 

Section 3.0 provides a brief summary of the physical and chemical 
characteristics of benzene and an overview of its production, uses, and emissions sources. 

This background section may be useful to someone who needs to develop a general perspective 
on the nature of benzene, how it is manufactured and consumed, and sources of emissions. 

Section 4.0 focuses on the production of benzene and the associated air 
emissions. For each major production source category described in Section 4.0, an example 
process description and a flow diagram(s) with potential emission points are given. Available 
emissions estimates are used to calculate emission factors that show the potential for benzene 
emissions before and after controls employed by industry. Also provided are estimates of 
emissions from process vents, equipment leaks, storage tanks, and wastewater. Individual 
companies that are reported in trade publications to produce benzene are named. 

Section 5.0 describes major source categories that use benzene as a feedstock to 
produce industrial organic chemicals. For each major production process, a description(s) of 
the process is given along with a process flow diagram(s). Potential emission points are 
identified on the diagrams and emission ranges are presented, where available. Individual 
companies that use benzene as a feedstock are reported. 


2-1 


Section 6.0 describes emission sources where benzene is emitted as the 


by-product of a process (such as petroleum refineries) and post-manufacturing activities where 
releases from benzene-containing products may occur (such as from gasoline distribution). 
Example process descriptions and flow diagrams are provided in addition to available emission 
factors for each major industrial category described in this section. 

Section 7.0 presents information on stationary combustion sources (such as 
municipal waste combustors) and area combustion sources (such as open burning). Example 
incinerator, furnace, or boiler diagrams are given, when appropriate. Emission factors are 
also given, when available. 

Section 8.0 provides a brief summary on benzene emissions from mobile 
sources. This section addresses both on-road and off-road sources. Section 9.0 summarizes 
available procedures for source sampling and analysis of benzene. This section provides an 
overview of applicable sampling procedures and cites references for those interested in 
conducting source tests. Section 10.0 presents a list of all the references Cited in this 
document. 


Appendix A presents a summary table of the emission factors contained in this 
document. This table also presents the factor quality rating and the Source Classification Code 
(SCC) or Area/Mobile Source (AMS) code associated with each emission factor. Appendix B 

presents a list of all the petroleum refmeries in the United States. 

Each emission factor listed in Sections 4.0 through 8.0 was assigned an emission 
factor rating (A, B, C, D, E, or U), based on the criteria for assigning data quality ratings and 
emission factor ratings as discussed in the document Procedures for Preparing Emission Factor 
Documents} The criteria for assigning the data quality ratings are as follows: 


A - Tests are performed by using an EPA reference test method, or when not 

applicable, a sound methodology. Tests are reported in enough detail for 


. 2-2 



adequate validation, and, raw data are provided that can be used to 
duplicate the emission results presented in the report. 

B - Tests are performed by a generally sound methodology, but lacking 

enough detail for adequate validation. Data are insufficient to completely 
duplicate the emission result presented in the report. 

C - Tests are based on an unproven or new methodology, or are lacking a 
significant amount of background information. 

D - Tests are based on generally unacceptable method, but the method may 
provide an order-of-magnitude value for the source. 


Once the data quality ratings for the source tests had been assigned, these 
ratings along with the number of source tests available for a given emission point were 
evaluated. Because of the almost impossible task of assigning a meaningful confidence limit to 
industry-specific variables (e.g., sample size vs. sample population, industry and facility 
variability, method of measurement), the use of a statistical confidence interval for establishing 
a representative emission factor for each source category was not practical. Therefore, some 
subjective quality rating was necessary. The following emission factor quality ratings were 
used in the emission factor tables in this document: 


A - Excellent. Emission factor is developed primarily from A- and B-rated 

source test data taken from many randomly chosen facilities in the industry 
population. The source category population is sufficiently specific to 
minimize variability. 

E Above average. Emission factor is developed primarily from A- or 

B-rated test data from a moderate number of facilities. Although no 
specific bias is evident, it is not clear if the facilities tested represent a 
random sample of the industry. As with the A rating, the source category 
population is sufficiently specific to minimize variability. 

C - Average. Emission factor is developed primarily from A-, B-, and C-rated 
test data from a reasonable number of facilities. Although no specific bias 
is evident, it is not clear if the facilities tested represent a random sample 
of the industry. As with the A rating, the source category population is 
sufficiently specific to minimize variability. 


2-3 


D - Below average. Emission factor is developed primarily form A-, B-, and 
C-rated test data from a small number of facilities, and there may be 
reason to suspect that these facilities do not represent a random sample of 
the industry. There also may be evidence of variability within the source 
population. 

E - Poor. Factor is developed from C- rated and D-rated test data from a very 
few number of facilities, and there may be reasons to suspect that the 
facilities tested do not represent a random sample of the industry. There 
also may be evidence of variability within the source category population. 

U - Unrated (Only used in the L&E documents). Emission factor is developed 
from source tests which have not been thoroughly evaluated, research 
papers, modeling data, or other sources that may lack supporting 
documentation. The data are not necessarily “poor,” but there is not 
enough information to rate the factors according to the rating protocol. 

This document does not contain any discussion of health or other environmental 
effects of benzene, nor does it include any discussion of ambient air levels. 


2-4 


SECTION 3.0 

BACKGROUND INFORMATION 


3.1 NATURE OF POLLUTANT 

Benzene is a clear, colorless, aromatic hydrocarbon that has a characteristic 
sickly sweet odor. It is both volatile and flammable. Chemical identification information for 
benzene is found in Table-3-1. Selected physical and chemical properties of benzene are 
presented in Table 3-2 A 7 

Benzene contains 92.3 percent carbon and 7.7 percent hydrogen (by mass). The 
benzene molecule is represented by a hexagon formed by six sets of carbon and hydrogen 
atoms bonded together with alternating single and double bonds. 


H 

I 

C 



3-1 





TABLE 3-1. CHEMICAL IDENTIFICATION OF BENZENE 


Chemical Name 

Benzene 

Synonyms 

Benzol, phenyl hydride, coal naphtha, 
phene, benxole, cyclohexatriene 

Molecular formula 

C 6 H 6 

Identification numbers 3 

CAS Registry 

71-43-2 

NIOSH RTECS 

CY 1400000 

DOT/UN/NA 

UN 1114; Benzene (Benzol) 

DOT Designation 

Flammable liquid 


Source: References 4 and 5. 

2 Chemical Abstract Services (CAS); National Institute of Occupational Safety and Health (NIOSH); Registry of 
Toxic Effects of Chemical Substances (RTECS); Department of Transportation/United Nations/North American 
(DOT/UN/NA). 

The chemical behavior of benzene indicates that the benzene molecule is more realistically 
represented as a resonance-stabilized structure: 



in which the carbon-to-carbon bonds are identical. The benzene molecule is the cornerstone 
tor aromatic compounds, all of which contain one or more benzene rings. 6 

Because of its resonance properties, benzene is highly stable for an unsaturated 
hydrocarbon. However, it does react with other compounds, primarily by substitution and, to 
a lesser degree, by addition. Some reactions can rupture the molecule or result in other groups 
cleaving to the molecule. Through all these types of reactions, many commercial chemicals 
are produced from benzene. 8 The most common commercial grade of benzene contains 50 to 


3-2 








TABLE 3-2. PHYSICAL AND CHEMICAL PROPERTIES OF BENZENE 


Property 

Value 

Molecular weight 

0.17 lbs (78.12 g) 

Melting point 

41.9°F(5.5°C) 

Boiling point at 1 atmosphere (760 mm Hg) 

176.18°F (80.1°C) 

Density, at 68°F (20°C) 

0.0141 lb/ft 3 (0.8794 g/cm 3 ) 

Physical state (ambient conditions) 

Liquid 

Color 

Clear 

Odor 

Characteristic 

Viscosity (absolute) at 68 °F (20 °C) 

0.6468 cP 

Surface tension at 77°F (25 °C) 

0.033 g/cm 3 (28.18 dynes/cm 3 ) 

Heat of vaporization at 176.18°F (80.100°C) 

33.871 KJ/Kg-mol (8095 Kcal/Kg-mol) 

Heat of combustion at constant pressure and 

77 °F (25 °C) (liquid C 6 H 6 to liquid H ; 0 and 
gaseous C0 2 ) 

41.836 KJ/g (9.999 Kcal/g) 

Odor threshold 

0.875 ppm 

Solubility: 


Water at 77 °F (25 °C) 

Very slightly soluble (0.180 g/100 mL, 

1800 ppm) 

Organic Solvents 

Soluble in alcohol, ether, acetone, carbon 
tetrachloride, carbon disulfide, and acetic 
acid 

Vapor pressure at 77 F (25 C) 

95.2 mm Hg (12.7 kPaj 

Auto ignition temperature 

1044°F (562°C) 

Flashpoint 

12°F (-11.1°C) (closed cup) 

Conversion factors (Vapor weight to volume) 

1 ppm = 319 mg/m 3 at 77°F (25°C); 

1 mg/L = 313 ppm 


Source: References 4, 5, 6, and 7. 


3-3 








100 percent benzene, the remainder consisting of toluene, xylene, and other constituents that 
distill below 248°F (120°C). 4 

Laboratory evaluations indicate that benzene is minimally photochemically 
reactive in the atmosphere compared to the reactivity of other hydrocarbons. Reactivity can be 
determined by comparing the influence that different hydrocarbons have on the oxidation rate 
of nitric oxide (NO) to nitrogen dioxide (N0 2 ), or the relative degradation rate of various 
hydrocarbons when reacted with hydroxyl radicals (OH), atomic oxygen or ozone. For 
example, based on the NO oxidation test, the photochemical reactivity rate of benzene was 
determined to be one-tenth that of propylene and one-third that of n-hexane. 9 

Benzene shows long-term stability in the atmosphere. 8 Oxidation of benzene 
will occur only under extreme conditions involving a catalyst or elevated temperature or 
pressure. Photolysis is possible only in the presence of sensitizers and is dependent oa 
wavelength absorption. Benzene does not absorb wavelengths longer than l.lxlO' 5 inches (in) 
(275 nanometers [nm]). 8 

In laboratory evaluation, benzene is predicted to form phenols and ring cleavage 
products when reacted with OH, and to form quinone and ring cleavage products when reacted 
with aromatic hydrogen. 6 Other products that are predicted to form from indirect reactions 
with benzene in the atmosphere include aldehydes, peroxides, and epoxides. Photodegradation 

of NO_ produces atomic oxygen, which can react with atmospheric benzene to form phenols 9 

3.2 OVERVIEW OF PRODUCTION AND USE 


During the eighteenth century, benzene was discovered to be a component of 
oil, gas, coal tar, and coal gas. The commercial production of benzene from coal 
carbonization began in the United States around 1941. It was used primarily as feedstock in 
the chemical manufacturing industry. 10 For United States industries, benzene is currently 
produced in the United States, the Virgin Islands, and Puerto Rico by 26 companies at 


3-4 


36 manufacturing facilities. 11 The majority of benzene production facilities in the United States 
are found in the vicinity of crude oil sources, predominantly located around the Texas and 
Louisiana Gulf coast. They are also scattered throughout Kentucky, Pennsylvania, Ohio, 
Illinois, and New Jersey. 11 

Domestic benzene production in 1992 was estimated at 2,350 million gallons 
(gal) (8,896 million L). 11 Production was expected to increase by approximately 3 to 
3.5 percent per year through 1994. Exports of benzene in 1993 were about 23 million gal (87 
million L), around 1 percent of the total amount produced in the United States. 12 

Benzene is produced domestically by five major processes. 12 Approximately 
45 percent of the benzene consumed in the United States is produced by the catalytic 
reforming/separation process. 11 With this process, the naphtha portion of crude oil is mixed 
with hydrogen, heated, and sent through catalytic reactors. 13 The effluent enters a separator 
while the hydrogen is flashed off. 13 The resulting liquid is fractionated and the light ends (Cj 
to C 4 ) are split. Catalytic reformate, from which aromatics are extracted, is the product. 13 

Approximately 22 percent of the benzene produced in the United States is 
derived from ethylene production. 11 Pyrolysis gasoline is a by-product formed from the steam 
cracking of natural gas concentrates, heavy naphthas, or gas oils to produce ethylene. 14 

Toluene dealkylation or toluene disproportionation processes account for 
another 25 percent of the United States production of benzene. 11 Toluene dealkylation 
produces benzene and methane from toluene or toluene-rich hydrocarbons through cracking 
processes using heat and hydrogen. The process may be either fixed-bed catalyst or thermal. 
Toluene disproportionation produces benzene and xylenes as co-products from toluene using 
similar processes. 15 

Three percent of benzene produced in the United States is derived from coke 
oven light oil distillation at coke by-product plants. 11 Light oil is recovered from coke oven 


3-5 


gas, usually by continuous countercurrent absorption in a high-boiling liquid from which it is 
stripped by steam distillation. 9 A light oil scrubber or spray tower removes the light oil from 
coke oven gas. 10 Benzene is recovered from the light oil by a number of processes, including 
fractionating to remove the lighter and heavier hydrocarbons^ hydrogenation, and conventional 
distillation. 


Finally, about 2 percent of benzene produced in the United States is derived as a 
coproduct from xylene isomerization. 11 Figure 3-1 presents a simplified production and use 
tree for benzene. Each major production process is shown, along with the percent of benzene 
derived from each process. The primary uses of benzene and the percentage for each use are 
also given in the figure. 

The major use of benzene is still as a feedstock for chemical production, as in 
the manufacture of ethylbenzene (and styrene). In 1992, the manufacture of ethylbenzene (and 
styrene) accounted for 53 percent of benzene consumption. 12 Ethylbenzene is formed by 
reacting benzene with ethylene and propylene using a catalyst such as anhydrous aluminum 
chloride or solid phosphoric acid. 8 Styrene is the product of dehydrogenation of 
ethylbenzene. 9 


Twenty-three percent of the benzene supply is used to produce cumene. 12 
Cumene is produced from benzene alkylation with propylene using solid phosphoric acid as a 
catalyst. 7 Cumene is oxidized to produce phenols and acetone. 12 Phenol is used to make resins 
and resin intermediates for epoxies and polycarbonates, and caprolactam for nylon. 12 Acetone 
is used to make solvents and plastics. 16 

Cyclohexane production accounts for 13 percent of benzene use. 12 Cyclohexane 
is produced by reducing benzene hydrogenated vapors using a nickel catalyst at 392°F 
(200°C). Almost all of cyclohexane is used to make nylon or nylon intermediates. 17 


3-6 


Benzene Production Proc©**©* 



3-7 








































































The production of nitrobenzene, from which aniline is made, accounts for 
5 percent of benzene consumption. Nitrobenzene is produced by the nitration of benzene with 
a concentrated acid mixture of nitric and sulfuric acid. Nitrobenzene is reduced to form 
aniline. 10 Aniline, in turn, is used to manufacture isocyanates for polyurethane foams, plastics, 
and dyes. 18 


Chlorobenzene production accounts for 2 percent of benzene use. The 
halogenation of hot benzene with chlorine yields chlorobenzene. Monochlorobenzene and 
dichlorobenzene are produced by halogenation with chlorine using a molybdenum chloride 
catalyst. 19 


The remainder of the benzene produced is consumed in the production of other 
chemicals. Other benzene-derived chemicals include linear alkylbenzene, resorcinol, and 
hydroquinone. 


Though much of the benzene consumed in the United States is used to 
manufacture chemicals, another important use is in gasoline blending. Aromatic 
hydrocarbons, including benzene, are added to vehicle fuels to enhance octane value. As lead 
content of fuels is reduced, the amount of aromatic hydrocarbons is increased to maintain 
octane rating, such that the benzene content in gasoline was increased in recent years. 4 The 
concentration of benzene in refmed gasoline depends on many variables, such as gasoline 
grade, refinery location and processes, and crude source. 6 The various sources of benzene 
emissions associated with gasoline marketing are discussed in Section 6.0, and benzene 
emissions associated with motor vehicles are discussed in Section 8.0 of this document. 

3.3 OVERVIEW OF EMISSIONS 

Sources of benzene emissions from its production and uses are typical of those 
found at any chemical production facility: 

• Process vents; 


3-8 


Equipment leaks; 


• Waste streams (secondary sources); 

• Transfer and storage; and 

• Accidental or emergency releases. 

These sources of benzene emissions are described in Sections 4.0 and 5.0 of this document. 

Miscellaneous sources of benzene including oil and gas production, glycol 
dehydrators, petroleum refineries, gasoline marketing, POTWs, landfills, and miscellaneous 
manufacturing processes are addressed in Section 6.0. Combustion sources emitting benzene 
are addressed in Section 7.0. Section 8.0 presents a discussion of benzene emissions from 
mobile sources. Recent work by the EPA Office of Mobile Sources on benzene in vehicle 
exhaust resulted in revised emission factors. 20 For off-road vehicles, EPA has also completed 
a recent study to estimate emissions. 


3-9 




























■ 








1 























■ 

■ 







SECTION 4.0 

EMISSIONS FROM BENZENE PRODUCTION 


This section presents information on the four major benzene production source 
categories that may discharge benzene air emissions. The four major processes for producing 
benzene are: 

• Catalytic reforming/separation; 

• Toluene dealkylation and disproportionation; 

• Ethylene production; and 

• Coke oven light oil distillation. 

For each of these production source categories, the following information is 
provided in the sections below: (1) a brief characterization of the national activity in the 
United States, (2) a process description, (3) benzene emissions characteristics, and (4) control 
technologies and techniques for reducing benzene emissions. In some cases, the current 
Federal regulations applicable to the source category are discussed. Table 4-1 lists U. S. 
producers of benzene and the type of production process used. 11 

Following the discussion of the major benzene production source categories, 
Section 4.5 contains a discussion of methods for estimating benzene emissions from process 
vents, equipment leaks, storage tanks, wastewater, and transfer operations. These emissions 
estimation methods are discussed in general terms and can be applied to the source categories 
in this section as well as the source categories in Section 5.0. 


4-1 


TABLE 4-1. BENZENE PRODUCTION FACILITIES 


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Dow Chemical U.S. A. Freeport, Texas 25 (95) Pyrolysis gasoline; captive 

Plaquemine, Louisiana 80 (303) Pyrolysis gasoline; captive 

_ 120 (454) _ Toluene; captive _ 











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Mobil Oil Corporation 10 (38) Pyrolysis gasoline 

Mobil Chemical Company, division 20 (76) Catalytic reformate; no captive use 

Petrochemicals Division Chalmette, Louisiana 

U.S. Marketing and Refining Division 







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4-6 


existence of particular facilities by consulting current listings or the plants themselves. The level of emissions from any given facility is a function of 
variables such as throughput and control measures, and should be determined through direct contacts with plant personnel. Reference SRI '93 
indicates these data reflect changes made in product locations as of January 1993. 









4.1 


CATALYTIC REFORMING/SEPARATION PROCESS 


Production of benzene by reforming/separation is associated with the production 
of toluene and xylene (BTX plants). Catalytic reforming is used to prepare high-octane 
blending stocks for gasoline production and for producing aromatics as separate chemicals. 

The reforming process, shown in Figure 4-1, 22 accounts for about 45 percent of all benzene 
produced in the United States. 12 In the following description of the reforming process, 
potential emission points are identified; however, not all of the emission points discussed in 
this section are always present at plants using this production process. Some companies have 
indicated that they have closed systems; others have indicated that process vent emissions are 
well-controlled by flares or scrubbers. 22 

4.1.1 Process Description for Catalytic Reforming/Separation 

The reforming process used at BTX plants (shown in Figure 4-1) can greatly 
increase the aromatic content of petroleum fractions by such reactions as dehydrogenation, 
isomerization and dehydrogenation, or cyclization. The usual feedstock in this process is a 
straight-run, hydrocracked, thermally cracked, or catalytically cracked naphtha. After the 
naphtha is hydrotreated to remove sulfur (Stream 1), it is mixed with recycled hydrogen 
(Stream 4) and heated. This feed (Stream 2) is sent through catalytic reactors in which the 
catalyst, usually platinum or rhenium chloride, converts paraffins to aromatic compounds. The 
product stream ^Stream 3) consists of excess hydrogen and a reformate nen m aromatics. 
Products from the reactor (Stream 3) are fed to the separation section, which separates the 
hydrogen gas from the liquid product. The hydrogen gas can be recycled to the reactor 
(Stream 4). The liquid product from the separator (Stream 5) is fed to a stabilizer (not shown 
in the figure). 22 The stabilizer is a fractionator in which more volatile, light hydrocarbons are 
removed from the high-octane liquid product. The liquid is then sent to a debutanizer (not 
shown in the figure). Aromatics (benzene, toluene, and mixed xylenes) are then extracted 
from the stabilized reformate. 22 


4-7 



© 





4-8 










































































Numerous solvents are available for the extraction of aromatics from the 
stabilized reformate stream. Glycols (tetraethylene glycol) and sulfolane 
(1,1-tetrahydrothiophene dioxide) are most commonly used. The processes in which these 
solvents are used are similar, so only the glycol process is described here. In the glycol 
process shown in Figure 4-2, aromatics are separated from the reformate in the extractor. 22 
The raffinate (stream 2) is water-washed and stored. The dissolved aromatics extract 
(Stream 1) is steam-stripped and the hydrocarbons separated from the solvent. The 
hydrocarbon stream (Stream 3) is water-washed to remove remaining solvent and is then 
heated and sent through clay towers to remove olefins (Stream 4). Benzene, toluene, and 
xylene (Stream 5) are then separated by a series of fractionation steps. 22 

4.1.2 Benzene Emissions from Catalytic Reforming/Separation 

The available information on benzene emissions from process vents, equipment 
leaks, storage vessels, wastewater collection and treatment systems, and product loading and 
transport operations associated with benzene production using the catalytic' 
reforming/separation process is presented below. Where a literature review revealed no 
source-specific emission factors for uncontrolled or controlled benzene emissions from these 
emission points from this process, the reader is referred to Section 4.5 of this chapter, which 
provides a general discussion of methods for estimating uncontrolled and controlled benzene 
emissions from these emission points. 

A literature search, a review of materials in the docket (A-79-27) for some 
National Emission Standards for Hazardous Air Pollutants (NESHAP) efforts on benzene, and 
information provided by the benzene production industry revealed no source-specific emission 
factors for benzene from catalytic reforming/separation. 22 However, information provided by 
the benzene production industry indicates that BTX is commonly produced in closed systems, 
and that any process vent emissions are well-controlled by flares and/or scrubbers. (See 
Section 4.5 of this chapter for a discussion of control devices.) 22 Furthermore, some 
descriptive data were found, indicating that benzene may be emitted from the 


4-9 



•Jd-Z*~Z9 - Oa3 



4-10 


Source: Reference 22. 































































































catalytic/reforming process during catalyst regeneration or replacement, during recycling of 
hydrogen gas to the reformer, and from the light gases taken from the separator. These 
potential emission points are labeled as A, B, and C, respectively, in Figure 4-1. 

One general estimate of the amount of benzene emitted by catalytic 
reforming/separation has been reported in the literature. In this reference, it was estimated 
that 1 percent of total benzene produced by catalytic reforming is emitted. 23 

Benzene may be emitted from separation solvent regeneration, raffinate wash 
water, and raffinate in association with the separation processes following catalytic reforming. 
These potential sources are shown as A, B, and C, respectively, in Figure 4-2. However, no 
specific data were found showing emission factors or estimates for benzene emissions from 
these potential sources. One discussion of the Sulfolane process indicated that 99.9-percent 
recovery of benzene was not unusual. Therefore, the 0.1 percent unrecovered benzene may be 
a rough general estimate of the benzene emissions from separation processes. 23 

4.2 TOLUENE DEALKYLATION AND TOLUENE DISPROPORTIONATION 

PROCESS 

Benzene can also be produced from toluene by hydrodealkylation (HDA) or 
disproportionation. The amount of benzene produced from toluene depends on the overall 
demand and price for benzene because benzene produced by HDA costs more than benzene 
produced through catalytic reforming or pyrolysis gasoline/ 4 At present, benzene production 
directly from toluene accounts for almost 30 percent of total benzene produced. 11 Growth in 
demand for toluene in gasoline (as an octane-boosting component for gasoline blending) 
appears to be slowing because of increased air quality legislation to remove aromatics from 
gasoline. (At present, gasoline blending accounts for 30 percent of the end use of toluene.) If 
toluene is removed from the gasoline pool to any great extent, its value is expected to drop 
because surpluses will occur. In such a scenario, increased use of toluene to produce benzene 
by HDA or disproportionation would be expected. 24 At present, production of benzene by the 
HDA and disproportionation processes accounts for 50 percent of toluene end use. 


4-11 


4.2.1 


Toluene Dealkylation 


Process Description 

Hydrodealkylation of toluene can be accomplished through thermal or catalytic 
processes. 25 The total dealkylation capacity is almost evenly distributed between the two 
' methods. 10 As shown in Figure 4-3, pure toluene (92 to 99 percent) or toluene (85 to 
90 percent) mixed with other heavier aromatics or paraffins from the benzene fractionation 
column is heated together with hydrogen- containing gas to 1,346°F (730°C) at a specified 
pressure (Stream 1) and is passed over a dealkylation catalyst in the reactor (Stream 2). 
Toluene reacts with the hydrogen to yield benzene and methane. The benzene may be 
separated from methane in a high-pressure separator (Stream 3) by flashing off the 
methane-containing gas. 25 

The product is then established (Stream 4), and benzene is recovered by 
distillation in the fractionalization column (Stream 5). 10 Recovered benzene is sent to storage 
(Stream 6). Unreacted toluene and some heavy aromatic by-products are recycled (Stream 7). 
About 70 to 85 percent conversion of toluene to benzene is accomplished per pass through the 
system, and the ultimate yield is 95 percent of the theoretical yield. Because there is a weight 
loss of about 23 percent, the difference in toluene and benzene prices must be high enough to 
justify use of the HDA process. 

Benzene Emissions 

The available information on benzene emissions from process vents, equipment 
leaks, storage vessels, wastewater collection and treatment systems, and product loading and 
transport operations associated with benzene production using the toluene dealkylation process 
was reviewed. No source-specific emission factors were found for benzene emissions from its 
production through dealkylation of toluene. The reader is referred to Section 4.5 of this 


4-12 



chapter, which provides a general discussion of methods for estimating uncontrolled and 
controlled benzene emissions from these emission points. • 

Potential sources of emissions from the dealkylation process include the 
separation of benzene and methane, distillation, catalyst regeneration, and stabilization. 23 
These potential sources are shown as emission points A, B, C, and D respectively, in 
Figure 4-3. 10,15,25 

4.2.2 Toluene Disproportionation 

Process Description 

Toluene disproportionation (or transalkylation) catalytically converts two 
molecules of toluene to one molecule each of benzene and xylene. 24 As shown in Figure 4-4, 
the basic process is similar to toluene hydrodealkylation, but can occur under less severe 
conditions. 15,26 Transalkylation operates at lower temperatures, consumes little hydrogen, and 
no loss of carbon to methane occurs as with HDA. 24 Toluene material is sent to a separator for 
removal of off-gases (Stream 3). The product is then established (Stream 4) and sent through 
clay towers (Stream 5). Benzene, toluene, and xylene are recovered by distillation, and 
unreacted toluene is recycled (Stream 6). Note that if benzene is the only product required, 
then HDA is a more economical and feasible process. 27 

Benzene Emissions 

No specific emission factors were found for benzene emissions from its 
production via toluene disproportionation. Potential sources of benzene emissions from this 
process are associated with the separation of benzene and xylene, catalyst regeneration, and 
heavy hydrocarbons that do not break down. 23 These potential sources are shown as points A, 
B, and C, respectively, in Figure 4-4. 


4-13 



Fractionation 



4-14 


Source: References 10, 15, and 25. 






















































Recycle Toluene 



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4-15 












































































































































4.3 


ETHYLENE PRODUCTION 


4.3.1 Process Description 

Ethylene is produced through pyrolysis of natural gas concentrates or petroleum 
fractions such as naphthas and atmospheric gas oils. 28 Pyrolysis gasoline is a liquid by-product 
formed as part of the steam-cracking process. The liquid pyrolysis gasoline is rich in benzene. 
Ethylene plants of the same production capacity, but using different feedstocks (ethane/propane 
versus naphthas/gas oils), will produce different amounts of pyrolysis gasoline with different 
benzene concentrations. For example, an ethylene plant producing 1 billion pounds 
(453.5 gigagrams [Gg]) of ethylene per year from ethane will produce about 16,097,023 lbs 
(7.3 Gg) pyrolysis gasoline with about 7,497,244 lbs (3.4 Gg) benzene in the pyrolysis 
gasoline. 28 A plant producing the same amount of ethylene from atmospheric gas oils will 
produce about 754,134,509 lbs (342 Gg) of pyrolysis gasoline containing 213,450,937 lbs 
(96.8 Gg) benzene. 28 

Because the benzene content of pyrolysis gasoline can be high, some plants 
recover motor gasoline, aromatics (BTX), or benzene from the pyrolysis gasoline. Table 4-1 
lists facilities reported to recover benzene from pyrolysis gasoline. However, benzene can be 
emitted from ethylene plants that produce pyrolysis gasoline but do not recover benzene. 

Table 4-2 lists ethylene producers and their locations. To locate most of the potential sources 
of benzene from ethylene/pyrolysis gasoline plants, information is included here on 
ethylene/pyrolysis gasoline production, as well as information on recovery of benzene from 
pyrolysis gasoline. But because ethylene plants using naphthas/gas oils as feedstocks produce 
more pyrolysis gasoline and more often treat the gasoline prior to storage, these types of plants 
are emphasized in the following discussion. 

Reference 28 provides more detailed information on ethylene plants using 
natural gas concentrates as feedstocks. In general, natural gas-using plants are less complex 
than naphtha-using plants. The potential emissions sources of benzene at the two types of 


4-16 



TABLE 4-2. ETHYLENE PRODUCERS - LOCATION AND CAPACITY 


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Eastman Chemical Company 

Texas Eastman Company _ Longview, Texas _ 1,400 (635) _ Mostly Captive 









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4-19 


Union Carbide Corporation Seadrift, Texas 880 (399) Captive 

Industrial Chemicals Division Taft, Louisiana 1,405 (637) Captive 

_ Texas City, Texas _ 1,400 (635) _ Mostly captive 









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4-20 


producers, locations, and capacities as of January 1993. 










plants are similar, with smaller amounts of benzene being emitted from natural gas 
concentrate-using plants. 

Ethylene/Pyrolysis Gasoline Production 

A process flow diagram for a plant producing ethylene from naphtha and/or gas 
oil is shown in Figure 4-5. Many older facilities use larger numbers of compressors (in 
parallel) than are shown in the flow diagrams in Figure 4-5. For reference, Table 4-3 lists 
stream descriptions and corresponding stream numbers in Figure 4-5. The description of the 
process is taken almost entirely from Reference 28. 

Naphtha and/or gas oil (Stream 1), diluted with steam, is fed in parallel to a 
number of gas- or oil-fired tubular pyrolysis furnaces. The fuel gas and oil (Stream 2) for 
these furnaces are supplied from gas and oil fractions removed from the cracked gas in later 
separation steps. Ethane and propane, which are present in the cracked gas and are separated 
in later distillation steps (Streams 35 and 38), are combined and recycled (Stream 3) through a 
separate cracking furnace. The resulting cracked gas is combined with the cracked gas from 
the naphtha/gas-oil furnaces (Stream 5). The flue gas from the pyrolysis furnaces is vented 
(Vent A on Figure 6). 

During operation, coke accumulates on the inside walls of the reactor coils, and 
each furnace must be periodically taken out of service for removal of the accumulated coke. 
Normally, one furnace is out of service for decoking at all times. Decoking is accomplished 
by passing steam and air through the coil while the furnace is maintained at an elevated 
temperature, effectively burning the carbon out of the coil. While a furnace is being decoked, 
the exhaust is diverted (Stream 7) to an emissions control device (Vent B) whose main function 
is to reduce particulate emissions. The collected particles are removed as a slurry (Stream 8). 

The cracked gas (Stream 4) leaving the pyrolysis furnaces is rapidly cooled 
(quenched) to 482 to 572°F (250 to 300°C) by passing it through transfer-line exchangers, 


4-21 



4-22 


Figure 4-5. Process Flow Diagram for Ethylene Production from Naphtha and/or Gas-Oil Feeds 









































































































































From Drying Traps 


»J<9S>"ZB _ Ob3 



4-23 


Figure 4-5. Process Flow Diagram for Ethylene Production from Naphtha and/or Gas-Oil Feeds, continued 


















































































































TABLE 4-3. STREAM DESIGNATIONS FOR FIGURE 4-5, PRODUCTION OF 
ETHYLENE FROM NAPHTHA AND/OR GAS-OIL FEEDS 


Stream Number 


Stream Description 


1 

2 

3 

4 

5 

6 

7 

8 

9 

10 
11 
12 

13 

14 

15 

16 

17 

18 

19 

20 
21 
22 

23 

24 

25 

26 
27 


Naphtha or gas oil feed 
Fuel gas and oil 
Ethane/propane recycle stream 
Cracked gas 
Cracked gas 

Recycled pyrolysis fuel oil from gasoline fractionator 
Furnace exhaust 

Slurry of collected furnace decoking particles 
Quenched cracked gas 
Surplus fuel oil 
Light fractions 

Overheads from gasoline fractionator 

Condensed organic phase 

Raw pyrolysis gasoline to intermediate storage 

Water phase (saturated with organics) from quench tower 

Recycled water phase from heat exchangers 

Surplus water from quench tower 

Wastewater blowdown from recycle steam generator 

Overheads from quench tower 

Water condensed during compression 

Organic fractions condensed during compression 

Acid gas stripped in amine stripper 

Diethanolamine (DEA) 

Liquid waste stream from caustic wash tower 
Liquid waste stream from caustic wash tower 
Process gas stream from caustic wash tower 
Solid waste stream from drying traps 


4-24 


(continued) 




TABLE 4-3. CONTINUED 


Stream Number 

28 

29 

30 

31 

32 

33 

34 

35 

36 

37 

38 

39 

40 

41 

42 

43 

44 

45 

46 

47 

48 

49 


Stream Description 

Process gas 

Hydrogen rich stream from demethanizer 

Methane rich stream from demethanizer 

C 2 components from de-ethanizer 

C 3 and heavier components from de-ethanizer 

Hydrogenated acethylene from acetylene convertor 

Overheads from ethylene fractionator 

Ethane to recycle pyrolysis furnace 

Overheads from depropanizer 

Propylene (purified) 

Propane to ethane/propane pyrolysis furnace 

C 4 and heavier components to debutanizer 

Overheads from debutanizer 

C 5 and heavier components from debutanizer 

Combined C 5 components and gasoline stripper bottoms 
fractions 

Light ends to cracked gas compressor 
C 5 and heavier components 
Superheated stream 
Stream and hydrocarbons 
Organic vapor from separator pot 
Organic vapor from separator pot 
Organic vapor from separator pot 


4-25 






which end pyrolysis and simultaneously generate steam. The streams from the transfer-line 
exchangers (Stream 5) are combined and further quenched by the injection of recycled 
pyrolysis fuel oil from the gasoline fractionator (Stream 6). 

The remaining operations shown in Figure 4-5 are required for separation of the 
various product fractions formed in the cracking of gas oil and/or naphtha; for removal of acid 
gases (primarily hydrogen sulfide [H 2 S]) and carbon dioxide (CCy and water; and for 
hydrogenation of acetylene compounds to olefins or paraffins. 

The quenched cracked gas (Stream 9) passes to the gasoline fractionator, where 
pyrolysis fuel oil is separated. Most of the fuel oil passes through water-cooled heat 
exchangers and is recycled (Stream 6) to the preceding oil-quenching operation. The surplus 
fuel oil (Stream 10), equivalent to the quantity initially present in the cracked gas, passes first 
to the fuel oil stripper, where light fractions are removed, and then to fuel oil storage. The 
light fractions (Stream 11) removed in the fuel oil stripper are recycled to the gasoline 
fractionator. The gasoline fractionator temperatures are well above the vaporization 
temperature of water, and the contained water remains as superheated steam, with the overhead 
stream containing the lighter cracked-gas components. 

The overhead stream from the gasoline fractionator (Stream 12) passes to the 
quench tower, where the temperature is further reduced, condensing most of the water and part 
of the C 5 and heavier compounds. The condensed organic phase (Stream 13) is stripped of the 
lighter components in the gasoline stripper and is passed to raw pyrolysis gasoline intermediate 
storage (Stream 14). Most of the water phase, which is saturated with organics, is separated in 
the quench tower (Stream 15), passed through water-cooled heat exchangers (Stream 16), and 
then recycled to the quench tower to provide the necessary cooling. The surplus water 
(Stream 17), approximately equivalent to the quantity of steam injected with the pyrolysis 
furnace feed, passes to the dilution steam generator, where it is vaporized and recycled as 
steam to the pyrolysis furnaces. Blowdown from the recycle steam generator is removed as a 
wastewater stream (Stream 18). 


4-26 


On leaving the quench tower, the pyrolysis gas is compressed to about 3.5 mPa 
in five stages. 29 The overhead stream from the quench tower (Stream 19) passes to a 
centrifugal charge-gas compressor (first three stages), where it is compressed. Water 
(Stream 20) and organic fractions (Stream 21) condensed during compression and cooling are 
recycled to the quench tower and gasoline stripper. 

Lubricating oil (seal oil) discharged from the charge-gas compressor is stripped 
of volatile organics in a separator pot before the oil is recirculated. The organic vapor is 
vented to the atmosphere (Vent G). Similar separator pots separate volatile organics from 
lubricating oil from both the ethylene and propylene refrigeration compressors (Streams 48 and 
49). 


Following compression, acid gas (H 2 S and C0 2 ) is removed by absorption in 
diethanolamine (DEA) or other similar solvents in the amine wash tower followed by a caustic 
wash step. The amine stripper strips the acid gas (Stream 22) from the saturated DEA and the 
DEA (Stream 23) is recycled to the amine wash tower. Very little blowdown from the DEA 

cycle is required. 

The waste caustic solution, blowdown from the DEA cycle, and wastewater 
from the caustic wash tower are neutralized, stripped of acid gas, and removed as liquid waste 
streams (Streams 24 and 25). The acid gas stripped from the DEA and caustic waste 
(Stream 22) passes to an emission control device (Vent D), primarily to control H 2 S emissions. 

Following acid gas removal, the remaining process gas stream (Stream 26) is 
further compressed and passed through drying traps containing a desiccant, where the water 
content is reduced to the low level necessary to prevent ice or hydrate formation in the low- 
temperature distillation operations. The drying traps are operated on a cyclic basis, with 
periodic regeneration necessary to remove accumulated water from the desiccant. The 
desiccant is regenerated with heated fuel gas and the effluent gas is routed to the fuel system. 
Fouling of the desiccant by polymer formation necessitates periodic desiccant replacement. 


4-27 


which results in the generation of a solid waste (Stream 27). However, with a normal 
desiccant service life of possibly several years, this waste source is relatively minor. 

With the exception of three catalytic hydrogenation operations, the remaining 
process steps involve a series of fractionations in which the various product fractions are 
successively separated. 

The demethanizer separates a mixture of hydrogen and methane from the C 2 and 
heavier components of the process gas (Stream 28). The demethanizer overhead stream 
(hydrogen and methane) is further separated into hydrogen-rich and methane-rich streams 
(Streams 29 and 30) in the low-temperature chilling section. The methane-rich stream is used 
primarily for furnace fuel. Hydrogen is required in the catalytic hydrogenation operations. 

The de-ethanizer separates the C 2 components (ethylene, ethane, and acetylene) 
(Stream 31) from the C 3 and heavier components (Stream 32). Following catalytic 
hydrogenation of acetylene to ethylene by the acetylene converter (Stream 33), the ethylene- 
ethane split is made by the ethylene fractionator. The overhead from the ethylene fractionator 
(Stream 34) is removed as the purified ethylene product, and the ethane fraction (Stream 35) is 
recycled to the ethane/propane cracking furnace. For the separation of binary mixtures with 
close boiling points, such as in the ethylene-ethane fractions, open heat pumps are 
thermodynamically the most attractive. Both heating and cooling duties have to be 
incorporated into the cascade refrigeration system for optimum energy utilization. 29 

The de-ethanizer bottoms (C 3 and heavier compounds) (Stream 32) pass to the 
depropanizer, where a C 3 -C 4 split is made. The depropanizer overhead stream (primarily 
propylene and propane) (Stream 36) passes to a catalytic hydrogenation reactor (C 3 converter), 
where traces of propadiene and methyl acetylene are hydrogenated. Following hydrogenation, 
the C 3 fraction passes to the propylene fractionator, where propylene is removed overhead as a 
purified product (Stream 37). The propane (Stream 38) is recycled to the ethane/propane 
pyrolysis furnace. 


4-28 



The C 4 and heavier components (Stream 39) from the depropanizer pass to the 
debutanizer, where a C 4 -C 5 split is made. The overhead C 4 stream (Stream 40) is removed as 
feed to a separate butadiene process. 

The stream containing C 5 and heavier compounds from the debutanizer 
(Stream 41) is combined with the bottoms fraction from the gasoline stripper as raw pyrolysis 
gasoline. The combined stream (Stream 42) is hydrogenated in the gasoline treatment section. 
Following the stripping of lights (Stream 43), which are recycled to the cracked-gas 
compressor, the C 5 and heavier compounds (Stream 44) are transferred to storage as treated 
pyrolysis gasoline. This stream contains benzene and other aromatics formed by pyrolysis. 

The three catalytic hydrogenation reactors for acetylene, C 3 compounds, and 
pyrolysis gasoline all require periodic regeneration of the catalyst to remove contaminants. 

The catalyst is generally regenerated every four to six months. At the start of regeneration, as 
superheated steam (Stream 45) is passed through a reactor, a mixture of steam and 
hydrocarbons leaving the reactor (Stream 46) is passed to the quench tower. After sufficient 
time has elapsed for stripping of organics (approximately 48 hours), the exhaust is directed to 
an atmospheric vent (Vent F) and a steam-air mixture is passed through the catalyst to remove 
residual carbon. This operation continues for an additional 24 to 48 hours. The presence of 
air during this phase of the regeneration prevents the vented vapor from being returned to the 
process. 


Because the olefms and di-olefms present in pyrolysis gasoline are unstable in 
motor gasoline and interfere with extraction of aromatics, they are hydrogenated prior to 
extraction of aromatics. 10 Also, as mentioned before, because the benzene content of pyrolysis 
gasoline can be high, some plants recover motor gasoline, aromatics (BTX), or benzene from 
the pyrolysis gasoline. 


4-29 


Recovery of Benzene from Pyrolysis Gasoline 

A process flow diagram for a plant producing benzene, toluene, and xylenes by 
hydrogenation of pyrolysis gasoline is presented in Figure 4-6. Pyrolysis gasoline is fed with 
make-up hydrogen into the first stage hydrogenation reactor (Stream 1), where olefins are 
hydrogenated. The reaction conditions are mild (104 to 203 °F [40 to 95 °C] and 147 to 
588 lb/in 2 [10 to 40 atmospheres pressure]). 10 

The catalyst in the first stage reactor (nickel or palladium) requires more 
frequent regeneration than most refinery catalysts because of the formation of gums. Catalyst 
may be regenerated about every 4 months and coke is burned off every 9 to 12 months. 10,30 

From the first reactor, the hydrogenated di-olefins and olefins are sent to a 
second reactor (Stream 2). Reactor effluent is then cooled and discharged into a separator 
(Stream 3). Part of the gas stream from the separator is recycled back to the reactor (Stream 4) 
after being scrubbed with caustic solution. The liquid phase from the separator is sent to a 
coalescer (Stream 5), where water is used to trap particles of coke formed in the reactor. 30 
Next, the light hydrocarbons are removed from the liquid in the stabilizer (Stream 6). At this 
point, the process becomes similar to the solvent extraction of reformate in the catalytic 
reforming of naphtha. The stabilized liquid is extracted with a solvent, usually Sulfolane or 
tetraethylene glycol (Stream 7). 

The raffinate (Stream 8) contains paraffins and may be sent to a cracking 
furnace to produce olefins. 30 The solvent may be regenerated (Streams 9 and 10). Dissolved 
aromatics (benzene, toluene, and xylene) are separated from the solvent by distillation 
(Stream 11) and sent through clay towers (Stream 12). Individual components (benzene, 
toluene, and xylene) are finally separated (Stream 13) and sent to storage. 

The above process may vary among facilities. For example. Stream 1 may be 
passed over additional catalyst, such as cobalt molybdenum, after being passed over a nickel or 


4-30 


Wastewater 


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Figure 4-6. Production of BTX by Hydrogenation of Pyrolysis Gasoline 






























































palladium catalyst. Also, the olefins produced from the raffinate stream (Stream 8) may be 
added to a gasoline process or sold as a reformer stock. 31 * 

4.3.2 Benzene Emissions from Ethylene Plants and Benzene Recovery from Pyrolysis 

Gasoline 

Production of ethylene from naphtha/gas oil does not produce large quantities of 
volatile organic compounds (VOC) or benzene emissions from process vents during normal 
operations. 28 Emission factors for benzene from sources at ethylene plants are shown in 
Table 4-4. The chief source of benzene emissions during normal operations is the charge gas 
compressor lubricating oil vent (Stream 47, Vent G in Figure 4-5). The emission factors in 
Table 4-4 were developed from data supplied by ethylene manufacturers. 

Most benzene emissions from ethylene plants are intermittent and occur during 
plant startup and shutdown, process upsets, and emergencies (Vent E). For example, benzene 
may be emitted from pressure relief devices, during intentional venting of off-specification 
materials, or during depressurizing and purging of equipment for maintenance. 28 Charge gas 
compressor and refrigeration compressor outages are also potential sources. Emissions from 
these compressors are generally short term in duration, but pollutants may be emitted at a high 
rate. 


In general, intermittent emissions and emissions from all pressure relief devices 
and emergency vents are routed through the main process vent (Vent E in Figure 4-5). The 
vent usually is controlled. The relief valve from the demethanizer is usually not routed to the 
main vent, but the valve is operated infrequently and emits mainly hydrogen and methane. 28 

Potential sources of benzene such as flue gas from the cracking furnace 
(Vent A), pyrolysis furnace decoking (Vent B), acid gas removal (Vent D), and hydrogenation 
catalyst regeneration (Vent F) generally are not significant sources. 28 Flue gas normally 
contains products of hydrogen and methane combustion. Emissions from pyrolysis furnace 
decoking consist of air, steam, C0 2 , CO, and particles of unbumed carbon. 28 Emissions from 


4-32 






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TABLE 4-4. BENZENE EMISSION FACTORS FOR A HYPOTHETICAL ETHYLENE PLANT” 


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acid gas removal are H 2 S, S0 2 , and C0 2 ; these emissions are generally controlled to recover 
H 2 S as sulfur or convert H 2 S to S0 2 . As discussed earlier, catalyst regeneration is infrequent 
and no significant concentrations of benzene have been reported as present in the emissions. 28 

Equipment leak benzene emissions at ethylene plants may originate from pumps, 
valves, process sampling, and continuous process analysis. Refer to Section 4.5.2 of this 
document, for information on emission estimates procedures, and available emission factors. 
Regarding equipment leak component counts, totals of 377 and 719 valves for benzene vapor 
and benzene liquid service respectively had been reported for ethylene plants. 32 Storage of 
ethylene in salt domes is not a potential source of benzene emissions because the ethylene 
generally does not contain benzene. 

The emission factor for benzene from storage vessels shown in Table 4-4 was 
derived from AP-42 equations. 33 No supporting data showing how the equations were applied 
were provided by the emission factor reference. 

Secondary emissions include those associated with handling and disposal of 
process wastewater. The emission factor in Table 4-4 was derived from estimates of 
wastewater produced and the estimated percent of the volatile organic compounds (VOC) 
emitted from the wastewater that is benzene. 

No data were available concerning benzene emissions from recovering benzene 
from pyrolysis gasoline. Likely sources include reactor vents, compressors, and any vents on 
the benzene column (Figure 4-6). 

The primary control techniques available for intermittent emissions of benzene 
(pressure relief valves, emergency vents) are flaring and combustion within industrial waste 
boilers. Other control methods are not as attractive because the emissions are infrequent and 
of short duration. The estimated control efficiency of flares is 98 percent or greater 34 while 
control efficiencies for industrial waste boilers vary depending upon design and operation. 28 


4-35 


For additional discussion on flares and industrial waste boilers as control methods, see 
Section 4.5.1. One ethylene producer that provided a process description stated that all 
process vents are connected to flares. However, it was not possible to determine how 
prevalent such systems are for ethylene production. 35 

Equipment leak emissions may be controlled by inspection/maintenance plans or 
use of equipment such as tandem seal pumps. For additional discussion on equipment leak 
emissions, see Section 4.5.2. Emissions from sampling lines can be controlled by piping 
sample line purge gas to the charge gas compressor or to a combustion chamber. Streams 
from process analyzers may be controlled in the same manner. 28 

The primary means of controlling emissions from pyrolysis gasoline or naphtha 
feedstock storage is floating roof tanks. Emissions can be reduced by 85 percent when internal 
floating roof devices are used. 28 For additional discussion on storage tank emissions, see 
Section 4.5.3. 

4.4 COKE OVEN AND COKE BY-PRODUCT RECOVERY PLANTS 


Most coke is produced in the U.S. using the by-product recovery process. In 
1994, there was one plant that used a “nonrecovery” process. This section will focus on the 
by-product recovery process because there are so few nonrecovery facilities in operation. 296 

4.4.1 Process Description 

Although most benzene is obtained from petroleum, some is recovered through 
distillation of coke oven light oil at coke by-product recovery plants. Light oil is a clear 
yellow-brown oil that contains coke oven gas components with boiling points between 32 and 
392°F (0 and 200°C). 26 Most by-product recovery plants recover light oil, but not all plants 
refine it. About 3.4 to 4.8 gal (13 to 18 liters [L]) of light oil can be recovered from the coke 


4-36 



oven gas evolved in coke ovens producing 0.91 ton (1 megagram [Mg]) of furnace coke (3 to 
4 gal/ton [10.3 to 13.7 L/Mg]). Light oil itself is 60 to 85 percent benzene. 37 

The coke by-product industry recovers various components of coke oven gas 

including: 

• Coal tar, a feedstock for producing electrode binder pitch, roofing pitch, 
road tar, and numerous basic chemicals; 

• Light oil, a source of benzene and other light aromatic chemicals; 

• Ammonia or ammonium sulfate, for agriculture and as chemical 
feedstocks; 

• Sulfur, a basic chemical commodity; 

• Naphthalene, used primarily as an intermediate in the production of 
organic chemicals; and 

• Coke oven gas, a high-quality fuel similar to natural gas. 38 

Because it is contained in the coke oven gas, benzene may be emitted from 
processes at by-product recovery plants that do not specifically recover or refine benzene. 
Table 4-5 lists coke oven batteries with by-product recovery plants in the United States. 36 
Figure 4-7 shows a process flow diagram for a representative coke by-product recovery 
plant. 37 39 The figure does not necessarily reflect any given plant, nor does it include all 
possible operations that could be found at a given facility. The number of units and the types 
of processes used varies among specific plants. For example, naphthalene recovery is not 
practiced at all plants, and some plants do not separate benzene from the light oil. Therefore, 
it is advisable to contact a specific facility to determine which processes are used before 
estimating emissions based on data in this document. 

Coal is converted to coke in coke ovens. About 99 percent of the U.S. 
production of coke uses the slot oven process, also referred to as the Kopper-Becker 
by-product coking process; the other 1 percent is produced in the original beehive ovens. 


4-37 


TABLE 4-5. COKE OVEN BATTERIES CURRENTLY OPERATING 

IN THE UNITED STATES 


Plant (Location) 

Battery Identification 
Number 

ABC Coke (Tarrant, AL) 

A 


5 


6 

Acme Steel (Chicago, IL) 

1 


2 

Armco, Inc. (Middletown, OH) 

1 


2 


3 

Armco, Inc. (Ashland, KY) 

3 


4 

Bethlehem Steel (Bethlehem, PA) 

A 


2 


3 

Bethlehem Steel (Bums Harbor, IN) 

1 


2 

Bethlehem Steel (Lackawanna, NY) 

7 


8 

Citizens Gas (Indianapolis, IN) 

E 


H 


1 

Empire Coke (Holt, AL) 

1 


2 

Erie Coke (Erie, PA) 

A 


B 

Geneva Steel (Provo, UT) 

1 


2 


3 


4 

Gulf States Steel (Gadsden, AL) 

2 


3 


4-38 


(continued) 





TABLE 4-5. CONTINUED 


Plant (Location) 

. Battery Identification 
Number 

Inland Steel (East Chicago, IN) 

6 


7 


9 


10 


11 

Koppers (Woodward, AL) 

1 


2A 


2B 


4A 


4B 


5 

LTV Steel (Cleveland, OH) 

6 


7 

LTV Steel (Pittsburgh, PA) 

PI 


P2 


P3N 


• P3S 


P4 

LTV Steel (Chicago, IL) 

2 

LTV Steel (Warren, OH) 

4 

National Steel (Ecorse, MI) 

5 

National Steel (Granite City, IL) 

A 


B 

New Bncton Coke fPortsmouth OH> 

1 

Sharon Steel (Monessen, PA) 

IB 


2 

Shenango (Pittsburgh, PA) 

1 


4 

Sloss Industries (Birmingham, AL) 

3 


4 


5 

Toledo Coke (Toledo, OH) 

C 

Tonawanda Coke (Buffalo, NY) 

1 


4-39 


(continued) 






TABLE 4-5. CONTINUED 


Plant (Location) 

Battery Identification 
Number 

USX (Clairton, PA) 

1 


2 

3 

7 

8 

9 

13 

14 

15 

19 

20 
B 

USX (Gary, IN) 23 

5 

7 

Wheeling-Pittsburgh (East Steubenville, WV) 1 

. 2 
3 

8 


Source: Reference 36. 

NOTE: This list is subject to change as market conditions change, facility ownership changes, plants are closed, 
etc. The reader should verify the existence of particular facilities by consulting current lists and/or the 
plants themselves. The level of benzene emissions from any given facility is a function of variables 
such as capacity, throughput and control measures, and should be determined through direct contacts 
with plant personnel. These operating plants and locations were current as of April 1, 1992. 


4-40 






Primary Coolar 



4-41 


Source: Reference 37 and 39. 



















































































Each oven has 3 main parts: coking chambers, heating chambers, and regenerative 
chambers. All of the chambers are lined with refractory (silica) brick. The coking chamber 
has ports in the top for charging of the coal. 22 

Each oven is typically capable of producing batches of 10 to 55 tons (9.1 to 
49.9 Mg) of coke product. A coke oven battery is a series of 20 to 100 coke ovens operated 
together, with offtake flues on either end of the ovens to remove gases produced. The 
individual ovens are charged and discharged at approximately equal time intervals during the 
coke cycle. The resulting constant flow of evolved gas from all the ovens in a battery helps 
to maintain a balance of pressure in the flues, collecting main, and stack. Process heat 
comes from the combustion of gases between the coke chambers. Approximately 40 percent 
of cleaned oven gas (after the removal of its byproducts) is used to heat the coke ovens. The 
rest is either used in other production processes related to steel production or sold. Coke 
oven gas is the most common fuel for underfiring coke ovens. 22 The coking time affects the 
type of coke produced. Furnace coke results when coal is coked for about 15 to 18 hours. 
Foundry coke, which is less common and is of higher quality (because if is harder and less 
readily ignited), results when coal is coked for about 25 to 30 hours. 37 


The coking process is actually thermal distillation of coal to separate volatile 
and nonvolatile components. Pulverized coal is charged into the top of an empty, but hot, 
coke oven. Peaks of coal form under the charging ports and a leveling har smoothes them 

out. Aficr the leveling bar is withdrawn, the topside charging ports are closed and the 

coking process begins. 


Heat for the coke ovens is supplied by a combustion system under the coke 
oven. The gases evolved during the thermal distillation are removed through the offtake 
main and sent to the by-product recovery plant for further processing. 


4-42 


After coking is completed (no volatiles remain), the coke in the chamber is 
ready to be removed. Doors on both sides of the chamber are opened and a ram is inserted 
into the chamber. The coke is pushed out of the oven in less than 1 minute, through the coke 
guide and into a quench car. After the coke is pushed from the oven, the doors are cleaned 
and repositioned. The oven is then ready to receive another charge of coal. 

The quench car carrying the hot coke moves along the battery tracks to a quench 
tower where approximately 270 gallons of water per ton of coke (1,130 L of water per Mg) 
are sprayed onto the coke mass to cool it from about 2000 to 180°F (1100 to 80°C) and to 
prevent it from igniting. The quench car may rely on a movable hood to collect particulate 
emissions, or it may have a scrubber car attached. The car then discharges the coke onto a 
wharf to drain and continue cooling. Gates on the wharf are opened to allow the coke to fall 
onto a conveyor that carries it to the crushing and screening station. After sizing, coke is 
sent to the blast furnace or to storage. 

As shown in Figure 4-7, coke oven gas leaves the oven at about 1292°F 
(700 °C) and is immediately contacted with flushing liquor (Stream 1). The flushing liquor 
reduces the temperature of the gas and acts as a collecting medium for condensed tar. The 
gas then passes into the suction main. About 80 percent of the tar is separated from the gas 
in the mains as “heavy” tar and is flushed to the tar decanter (Stream 2). 37 Another 
20 percent of the tar is “light” tar, which is cleaner and less viscous, and is condensed and 
collected in the primary cooler. 39 Smaller amounts of “tar fog” are removed from the gas by 
collectors (electrostatic precipitators or gas scrubbers) (Stream 4). 37 Light tar and tar fog is 
collected in the tar intercept sump (stream 6) and is routed to the tar decanter (Stream 5). 

Depending on plant design, the heavy and light tar streams (Streams 2 and 5) 
may be merged or separated. The tar is separated from the flushing liquor by gravity in the tar 
decanter. Recovered flushing liquor is returned to the Flushing Liquor Circulation Tank 
(Stream7) and re-used. Tar from the decanter is further refined in the tar dewater tank 


4-43 


(Stream 3). Tar may be sold to coal tar refiners or it may be refined farther on site. Tar and 
tar products are stored on site in tanks. 

Wastewater processing can recover phenol (Stream 8) and ammonia, with the 
ammonia routinely being reinjected into the gas stream (Stream 9). Ammonia salts or 
ammonia can be recovered by several processes. Traditionally, the ammonia-containing coke 
oven gas is contacted with sulfuric acid (Stream 10), and ammonium sulfate crystals are 
recovered (Stream 11). The coke oven gas from which tar and ammonia have been 
recovered is sent to the final cooler (Stream 12). The final cooler is generally a spray tower, 
with water serving as the cooling medium. 37 

Three types of final coolers and naphthalene recovery technologies are 
currently used: (1) direct cooling with water and naphthalene recovery by physical 
separation, (2) direct cooling with water and naphthalene recovery in the tar bottom of the 
final cooler, and (3) direct cooling with wash oil and naphthalene recovery in the wash oil. 37 
Most plants use direct water final coolers and recover naphthalene by physical separation. 37 
In this method, naphthalene in the coke oven gas is condensed in the cooling medium and 
separated by gravity (Stream 13). After the naphthalene is separated, the water is sent to a 
cooling tower (Stream 14) and recirculated to the final cooler (Stream 15). The coke oven 
gas that leaves the final cooler is sent to the light oil processing segment of the plant 
(Stream 16). 


As shown in Figure 4-7, light oil is primarily recovered from coke oven gas 
by continuous countercurrent absorption in a high-boiling liquid from which it is stripped by 
steam distillation. 10 Coke oven gas is introduced into a light oil scrubber (Stream 16). 
Packed or tray towers have been used in this phase of the process, but spray towers are now 
commonly used. 10 Wash oil is introduced into the top of the tower (Stream 17) and is 
circulated through the contacting stages of the tower at around 0.11 to .019 gal/ft 3 (1.5 to 
2.5 liters per cubic meter [L/m3]) of coke oven gas. 39 At a temperature of about 86°F 
(30°C), a light oil scrubber will remove 95 percent of the light oil from coke oven gas. The 


4-44 


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benzene-containing wash oil is steam-stripped (Stream 18) to recover the light oil. 39 Steam 
and stripped vapors are condensed and separated (Streams 19 and 20). The light oil is sent to 
storage (Stream 21). 37,39 

To recover the benzene present in the light oil, processes such as Litol 
(licensed by Houdry) or Hydeal (licensed by UOP) are used. Figure 4-8 shows a process 
diagram of the Litol process. The following discussion of the Litol process is drawn from 
two published descriptions of the process. 40,41 

The light oil is preffactionated (Stream 1) to remove the C 5 and lighter 
fractions, and the C 9 and heavier fractions (Stream 2). The remaining “heart cut” is sent to a 
vaporizer, where it contacts gas with a high hydrogen content (Stream 3). The light oil and 
hydrogen then flow to a pretreat reactor (Stream 4), where styrene, di-olefins, and some 
sulfur compounds are hydrogenated (at about 572 °F [300 °Cj). The partially hydrogenated 
stream is heated by the charge heater to the temperature required for the main reactor 
(Stream 5). 


The stream is then sent through a set of fixed-bed (Litol) reactors (Streams 6 
and 7), where all remaining sulfur compounds are converted to H 2 S and organics are 
dehydrogenated or dealkylated. The reactor effluent is cooled by post-reactor exchangers 
(Streams 8 and 9). At the flash drum, aromatics are condensed and separated from the gas 
stream (Stream 10). At the stabilizer, additional gas is removed, resulting in a hot liquid fuel 
for clay treatment (Stream 11). The clay treater removes the last trace of unsaturates from 
the aromatics (Stream 12). Conventional distillation yields pure benzene followed by pure 
toluene (Stream 13). Benzene product may then be sent to storage (Stream 14). 40,41 

4.4.2 Benzene Emissions 

Benzene may be emitted from many points in a coke and coke by-product 
plant; emissions are not limited to the benzene recovery section of the process. The coke 


4-46 



ovens themselves are potential sources of benzene emissions from the charging operation, 
leaking coke oven doors, topside port lids and offtake systems on the topside of the battery, 
collecting mains, and bypass/bleeder stacks. 36 

During charging, moist coal contacts the hot oven floor and walls and, as a 
result, the release of volatile components begins immediately. Control of charging emissions 
is more dependent on operating procedures than on equipment. Control options include 
staged charging, sequential charging, and use of wet scrubbers on larry cars (the mobile 
hoppers that discharge the coal). 

Staged charging involves pouring coal into the coke ovens so that an exit space 
for the generated gases is constantly maintained. 42 The hoppers delivering the coal are 
discharged such that emissions are contained in the ovens and collecting mains by steam 
aspiration. Generally, a maximum of two hoppers are discharging at the same time. 

In sequential charging, the first hoppers are still discharging when subsequent 
hoppers begin discharging coal. As with staged charging, the coke ovens are under 
aspiration in sequential charging. The sequential charging procedure is designed to shorten 
the charging time. 

In the use of wet scrubbers on larry cars, the scrubber emissions are contained 
by hoods or shrouds that are lowered over the charging ports. 

Another potential source of benzene emissions at coke ovens is leaking doors. 
The doors are sealed before the coking process begins. Some doors have a flexible metal 
band or rigid knife edge as a seal. The seal is formed by condensation of escaping tars on 
the door's metal edge. Other doors are sealed by hand by troweling a mixture into the 
opening between the coke oven door and door frame. After the coking process is complete, 
the doors are opened to push the coked coal out into special railroad cars called quench cars 
for transport to the quench tower. Quenched coke is then discharged onto a “coke wharf” to 


4-47 


allow quench water to drain and to let the coke cool. Control techniques for leaking doors 
include oven door seal technology, pressure differential devices, hoods/shrouds over the 
doors, and the use of more efficient operating/maintenance procedures. 42 

Oven door seal technology relies on the principle of producing a resistance to 
the flow of gases out of the coke oven. This resistance may be produced by a metal-to-metal 
seal, a resilient soft seal, or a luted seal (applying a slurry mixture of clay, coal, and other 
materials). Small cracks and defects in the seal allow pollutants to escape from the coke 
oven early in the cycle. The magnitude of the leak is determined by the size of the opening, 
the pressure drop between the oven and the atmosphere, and the composition of the 
emissions. 


The effectiveness of a pressure differential control device depends on the 
ability of the device to reduce or reverse the pressure differential across any defects, in the 
door seal. These systems either provide a channel to permit gases that evolve at the bottom 
of the oven to escape to the collecting main, or the systems provide external pressure on the 
seal through the use of steam or inert gases. 

Oven door emissions also can be reduced by collecting the leaking gases and 
particulates and subsequently removing these pollutants from the air stream. A suction hood 
above each door with a wet electrostatic precipitator for fume removal is an example of this 
type of system. 

Other control techniques rely on operating and maintenance procedures rather 
than only hardware. Operating procedures for emission reduction could include changes in 
the oven cycle times and temperatures, the amount and placement of each charge, and any 
adjustments of the end-door while the oven is on line. Maintenance procedures include 
routine inspection, replacement, and repair of control devices and doors. 


4-48 


Topside leaks are those occurring from rims of charging ports and standpipe 
leaks on the top of the coke oven. These leaks are primarily controlled by proper 
maintenance and operating procedures that include: 42 

• Replacement of warped lids; 

• Cleaning carbon deposits or other obstructions from the mating 
surfaces of lids or their seats; 

• Patching or replacing cracked standpipes; 

• Sealing lids after a charge or whenever necessary with lute; and 

• Sealing cracks at the base of a standpipe with lute. 

Luting mixtures are generally prepared by plant personnel according to 
formulas developed by each plant. The consistency (thickness) of the mixture is adjusted to 
suit different applications. 

There are few emission factors specifically for benzene emissions at coke 
ovens. One test that examined emissions of door leaks detected benzene in the emissions. 42 
The coke oven doors being tested were controlled with a collecting device, which then fed 
the collected emissions to a wet electrostatic precipitator. Tests at the precipitator inlet 
showed benzene concentrations of 1.9 x 10' 7 to 6.2 x 10‘ 7 lb/ft 3 (1 to 3 parts per million 
[ppm] or about 3 to 10 milligrams per cubic meter [Mg/m3]). These data translated into an 
estimated benzene emission factor of 1.3 lb to 5.3 lb (0 6 to 2 4 kilograms [kg]) benzene pe*- 
hour of operation for coke oven doors. In addition to coke oven door emissions, benzene 
may also be emitted from the coke oven bypass stack at a rate of 22 lbs/ton of coal charged 
(11,000 g/Mg) uncontrolled, 0.22 Ibs/ton of coal charged (110 g/Mg) controlled with 
flare. 296 No additional emission factors for benzene"and coke ovens were found in the 
literature. However, an analysis of coke oven gas indicated a benzene content of 
1.3 x 10‘ 3 to 2.2 x 10‘ 3 lb/ft 3 (21.4 to 35.8 grams per cubic meter [g/m 3 ]). 


4-49 


Other potential sources of benzene emissions associated with the by-product 
recovery plant are given in Table 4-6, along with emission factors. 37,43 

Equipment leaks may also contribute to benzene emissions. Emission factors 
for pumps, valves, etc., at furnace coke and foundry coke by-product recovery plants are 
shown in Tables 4-7 and 4-8, respectively. 37,43 The following paragraphs describe the 
potential sources of benzene emissions listed in Tables 4-6, 4-7, and 4-8. Emission sources 
and control technologies are described in groups of related processes, beginning with the 
final cooling unit. 

The fmal cooling unit itself is not a source of benzene because coolers are 
closed systems. However, the induced-draft cooling towers used in conjunction with 
direct-water and tar-bottom fmal coolers are potential sources of benzene. Benzene can be 
condensed in the direct-contact cooling water, and in the cooling tower, lighter components 
(such as benzene) will be stripped from the recirculating cooling water. The emission factor 
of 0.54 pound per ton (lb/ton) (270 g/Mg) coke shown in Table 4-6 was based on actual 
measurements of benzene concentrations and volumetric gas flow rates taken from source 
testing reports. 37 


Use of a wash oil fmal cooler effectively eliminates the benzene emissions 
associated with direct water or tar bottom coolers because the wash oil is cooled by an 
indirect heat exchanger, thereby eliminating the need for a cooling tower. 37 Wash oil is 
separated after it leaves the heat exchanger and recirculates back through the circulation tank 
to the final cooler. 

Coke by-product recovery plants may recover naphthalene by condensing it 
from the coke oven gas and separating it from the cooling water by flotation. Benzene may 
be emitted from most naphthalene separation and processing operations. 37 Vapors from 
naphthalene separation tanks have been reported to contain benzene, benzene homologs, and 
other aromatic hydrocarbons. 37 The emission factors for naphthalene separation and 


4-50 


TABLE 4-6. SUMMARY OF BENZENE EMISSION FACTORS FOR FURNACE AND 
F( >UNDRY COKE BY-PRODUCT RECOVERY PLANTS 


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4-53 













TABLE 4-7. SUMMARY OF BENZENE EMISSION FACTORS FOR EQUIPMENT LEAKS AT 

FURNACE COKE BY-PRODUCT RECOVERY PLANTS 


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4-54 


Closed-purge sampling _ (100) 











TABLE 4-7. CONTINUED 


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4-56 


Sampling Connections Uncontrolled 0.51 (0.23) 0.62(0.28) 

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. 4-57 












processing shown in Table 4-6 are based on source testing data from a flotation unit, drying 
tank, and melt pit at a coke by-product recovery plant. 37 ' 

Benzene may also be emitted from the light oil plant, which includes the 
light-oil condenser vent, light oil decanter, storage tank, intercepting sumps, the wash-oil 
decanter, wash-oil circulation tank(s), and BTX storage. A control technique required by the 
benzene NESHAP is the use of gas blanketing with clean coke oven gas from the gas holder 
(or battery underfire system). 44 With this technology, a positive (or negative) pressure 
blanket of clean coke oven gas is piped to the light oil plant and the enclosed sources are 
connected to the blanketing line. Using a series of piping connections and flow inducing 
devices (if necessary), vapor emissions from the enclosed sources are transported back into 
the clean gas system (the coke-oven battery holder, the collecting main, or another point in 
the by-product recovery process). 

Ultimate control of the vapors is accomplished by the combustion of the coke 
oven gas. 37 Such systems are currently in use at some by-product recovery plants and 
reportedly have operated without difficulty. Examples of gases that may be used as the gas 
blanket include dirty or clean coke gas, nitrogen, or natural gas. 37 The control efficiency is 
estimated to be 98 percent. 37,44 The control technique required by the benzene NESHAP for 
the light oil sump is a tightly fitting, gasketed cover with an estimated 96-percent 
efficiency. 44 The emission factors for benzene sources in the light oil plant shown in 
Table 4-6 are based on source tests. 37 

Sources of benzene emissions from tar processing include the tar decanter, the 
tar-intercepting sump, tar dewatering and storage, and the flushing-liquor circulation tank. 
Emission factors for these sources are shown in Table 4-6. 

Benzene emissions from the tar decanter are sensitive to two operating 
practices: residence time in the separator and optimal heating of the decanter. 37 These two 
variables should be kept in mind when using the emission factors presented in Table 4-6. 


4-58 


Benzene is emitted from tar decanters through vents. Coke oven gas can be mechanically 
entrained with the tar and liquor that are fed into the decanter. Because tar is fed into the 
decanter at a slightly higher pressure, the coke oven gas will build up in the decanter if it is 
not vented. 37 Emissions were measured at tar decanters at several locations in the United 
States and the emission factor shown in Table 4-6 is the average of the test values. 37 

The water that separates from the tar in the decanter is flushing liquor, which 
is used to cool the gas leaving the coke oven. Excess flushing liquor is stored in the excess 
ammonia liquor tank. Benzene may be emitted from the flushing liquor circulation tank and 
the excess ammonia liquor tank. The emission factor of 0.026 lb benzene/ton (13 g 
benzene/Mg) coke produced was derived from a source test of fugitive emissions from a 
primary cooler condensate tank. It was assumed that the condensate tank was similar in 
design and in liquids stored as the ammonia liquor and the flushing liquor circulation 
tanks . 296 The actual benzene emission rate from the flushing liquor circulation tank and 
excess ammonia liquor tank depends on the number of tanks, the number of vents, and the 
geometry of the tanks. 37 

The tar-intercepting sump is a type of decanter that accepts light tar and 
condensate from the primary cooler. Some of this condensate may be used to make up 
flushing liquor and some may be forwarded to ammonia recovery. 37 No significant benzene 
emissions have been identified from the recovery of ammonia, but benzene can be emitted 
from the intercepting sump. An emission factor of 0.019 Ib/ton (9.5 g benzene/Mg) coke 
was reported in the literature. 296 

Tar dewatering may be accomplished by steam heating or centrifugal 
separation or a combination of the two methods. Use of centrifugal separation will probably 
not be a source of benzene emissions directly, but benzene may be emitted as a fugitive 
emission if storage vessels are used. 39 In steam heating, benzene could be driven off in the 
vapors. The emission factor for tar dewatering in Table 4-6 was derived by averaging three 
factors (0.082, 0.019, and 0.0258 lb benzene/ton coke [41, 9.5, and 12.9 g benzene/Mg 


4-59 


coke]) based on source tests at tar dewatering tanks. 37 Gas blanketing is the control 
technology required by the benzene NESHAP for tar processing. 

The final source of benzene emissions at coke by-product recovery plants is 
leaks from equipment such as pumps, valves, exhausters, pressure relief devices, sampling 
connection systems, and open-ended lines. Emission factors are shown in Tables 4-7 and 4-8 
and are based on emission factors from a comprehensive survey of petroleum refineries and 
the percent of benzene in the liquid associated with each type of equipment. 37 Two different 
sets of emission factors are presented, one set for a plant practicing light oil and BTX 
recovery and one set for a plant producing refined benzene in addition to light oil. Emission 
factors for exhausters were derived by multiplying the VOC emission factor for compressors 
in hydrogen service and refineries by 0.235, the measured ratio of benzene to nonmethane 
hydrocarbons present in the coke oven gas at the exhausters. 37 

To control benzene emissions from process vessels, storage tanks, and tar- 
interrupting sumps as required by the benzene NESHAP, all openings must be enclosed or 
sealed. All gases must be routed to a gas collection system (or similar configuration) where 
the benzene in the gas will be removed or destroyed. Alternately, the gases may be routed 
through a closed vent system to a carbon absorber or vapor incinerator that is at least 
98 percent efficient. See Section 4.5 for a discussion of these types of process control 
devices. 44 The control techniques required by the benzene NESHAP to control benzene 
emissions from equipment leaks are presented in Table 4-9. 

For the nonrecovery process, benzene emissions for coal charging are 
3.6 x 10' 5 lb/ton of coal charged (1.8 x 10' 2 g/Mg). Emissions from pushing and quenching 
are expected to be similar to those from the by-product recovery process. Additional 
benzene emissions occur from the combustion stack of nonrecovery batteries at the rate of 
5.1 x W 4 lb/ton of coal charged (0.26 g/Mg). 296 


4-60 


TABLE 4-9. TECHNIQUES TO CONTROL BENZENE EMISSIONS FROM 
EQUIPMENT LEAKS REQUIRED BY THE BENZENE NESHAP FOR COKE 

BY-PRODUCT RECOVERY PLANTS 


Emission Points 

Control Technique (% efficiency) 

Pumps 

Monthly Inspection 2 (83) 


Dual Mechanical Seals (100) 

Valves 

Monthly Inspection 2 (73) 


Sealed-Bellows Valves (100) 

Exhausters 

Quarterly Inspections 2 (55) 


Degassing Reservoir Vents (100) 

Pressure-Relief Devices 

Rupture Disc System (100) 

Sampling Connection Systems 

Closed-Purge Sampling (100) 

Open-Ended Lines 

Cap or Plug (100) 


Source: Reference 44. 

1 Inspection and maintenance programs include tightening seals, replacing manufacturing equipment, etc. 

4.5 METHODS FOR ESTIMATING BENZENE EMISSIONS FROM EMISSION 

SOURCES 

In this section, the sources of benzene emissions from process vents, equipment 
leaks, storage tanks, wastewater, and transfer operations are summarized, along with the 
types of controls currently available for use in the industry. In addition, an overview of 
methods for estimating uncontrolled and controlled emissions of benzene is 
presented where available. Current Federal regulations applicable to these benzene emission 
sources are identified. The information provided in this section is applicable to benzene 
production facilities (discussed earlier in this chapter) as well as to facilities that use benzene 
as a feedstock to produce cyclic intermediates (discussed in Chapter 5.0). 


4-61 





4.5.1 


Process Vent Emissions. Controls , and Regulations 


Benzene emissions can occur from any process vent in any chemical production 
operation that manufactures or uses benzene. Section 4.0 of this document contains a 
discussion of chemical operations that manufacture benzene, whereas Section 5.0 contains a 
discussion of chemical operations that use benzene as feedstock. Chemical operations that 
emit benzene include air oxidation processes, reactor processes, and distillation operations. 

In air oxidation processes, one or more chemicals are reacted with oxygen supplied as air or 
air enriched with oxygen to create a product. With reactor processes, one or more chemicals 
are reacted with another chemical (besides oxygen) and chemically altered to create one or 
more new products. In distillation, one or more inlet feed streams is separated into two or 
more outlet product streams, each product stream having component concentrations different 
from those in the feed streams. During separation, the more volatile components are 
concentrated in the vapor phase and the less volatile components in the liquid phase. 45 

Calculations for estimating emissions from any of these three processes are 
specific to the type of vent stream and the type of control in place. 

Two general types of methods are used for controlling benzene emissions from 
process vents: recovery devices and combustion devices. Examples of each type of control 
device that can be used to comply with air pollution control standards, along with its 
estimated control efficiency, are summarized in Tables 4-10 and 4-11 and discussed briefly 
below. 45 The reader should keep in mind that the most appropriate recovery control device, 
as well as its effectiveness, is highly dependent upon flow rate, concentration, chemical and 
physical properties of the vent stream, contaminants present, and stream temperature. To 
achieve optimal control efficiency with recovery devices, several stream characteristics must 
remain within a certain range. Combustion control devices are less dependent upon these 
process and vent stream characteristics; however, combustion temperature and stream flow 
must remain within a certain range to ensure complete combustion. 46 


4-62 





TABLE 4-10. CONTROL TECHNOLOGIES THAT FORM THE BASIS OF AIR 

POLLUTION CONTROL STANDARDS 



Control Levels 


Design Conditions to Meet 



Type 

Achievable 


Control Level 


Comments 

Flares 

* 98% 

• 

Flame present at all times - 

• 

Destroys rather 




monitor pilot 


than recovers 



• 

Non-assisted Flares - 


organics 




> 200 Btu/scf heating value, 

• 

Smoking 




and 60 ft/sec (18 m/sec) 


allowed for 




maximum exit velocity 


5 min/2 hr 



• 

Air and Steam Assisted 

• 

Not used on 




Flares - > 300 Btu/scf 


corrosive 




heating value, and maximum 
exit velocity based on Btu 
content formula 


streams 

Industrial 

^ 98% 

• 

Vent stream directly into 

• 

Destroys rather 

Boilers/Process 



flame 


than recovers 

Heaters 





organics 

Thermal 

^ 98%, or 

• 

1600°F (871 °C) Combustion 

• 

Destroys rather 

Oxidation 

20 ppm 


temperature 


than recovers 



• 

0.75 sec. residence 


organics 



• 

For halogenated streams 

• 

May need vapor 




2000°F (1093°C), 1.0 sec. 


holder on 




and use a scrubber on outlet 


intermittent 



• 

Proper mixing 


streams 

Adsorption 

a 95% 

• 

Adequate quantity and 

• 

Most efficient on 




appropriate quality of carbon 


streams with low 



• 

Gas stream receives 


relative humidity 




appropriate conditioning 


(<50 percent). 




(cooling, filtering) 

• 

Recovers 



• 

Appropriate regeneration and 
cooling of carbon beds before 
breakthrough occurs 


organics 


Source: Reference 45. 


4-63 





TABLE 4-11. OTHER CONTROL TECHNOLOGIES THAT CAN BE USED 

TO MEET STANDARDS 


Type 

Estimated 

Control 

Level 

Critical Variables 

That Affect Control Level 

Comments 

Catalytic 

Oxidation 

up to 98 % 

• Dependent on 

compounds, temp, and 
catalyst bed size 

• Destroys rather than 
recovers organics 

• Technical limitations 
include particulate or 
compounds that poison 
catalysts 

Absorption 

50 to 95 % 

• Solubility of gas stream 
in the absorbent 

• Good contact between 
absorbent and gas 
stream 

• Appropriate absorbent 
needed may not be 
readily available 

• Disposal of spent 
absorbent may require 
special treatment 
procedures, and 
recovery of organic from 
absorbent may be time 
consuming 

• Preferable on 
concentrated streams 

Condensation 

50 to 95 % 

• Proper design of the 
heat exchanger 

• Proper flow and 
temperature of coolant 

• Preferable on 
concentrated streams 

• Recovers organics 


Source: Reference 45. 


4-64 





Three types of recovery devices have been identified for controlling benzene 
emissions: condensation, absorption, and adsorption. With a condensation-type recovery 
device, all or part of the condensible components of the vapor phase are converted to a liquid 
phase. Condensation occurs as heat from the vapor phase is transferred to a cooling medium. 
The most common type of condensation device is a surface condenser, where the coolant and 
vapor phases are separated by a tube wall and never come in direct contact with each other. 
Efficiency is dependent upon the type of vapor stream entering the condenser and the flow rate 
and temperature of the cooling medium. Condenser efficiency varies from 50 to 95 percent. 
Stream temperature and the organic concentration level in the stream must remain within a 
certain range to ensure optimal control efficiency. 46 

In absorption, one or more components of a gas stream are selectively transferred 
to a solvent liquid. Control devices in this category include spray towers, venturi scrubbers, 
packed columns, and plate columns. Absorption efficiency is dependent upon the type of 
solvent liquid used, as well as design and operating conditions. Absorption is desirable if there 
is a high concentration of compound in the vent stream that can be recovered for reuse. For 
example, in the manufacture of monochlorobenzene, absorbers are used to recover benzene for 
reuse as a feedstock. 46 Stream temperature, specific gravity (the degree of adsorbing liquid 
saturation), and the organic concentration level must remain within a certain range to ensure 
optimal control efficiency. 46 Absorbers are generally not used on streams with VOC 
concentrations below 300 ppmv. 45 Control efficiencies vary from 50 to 95 percent. 45 

In adsorption, the process vent gas stream contains a component (adsorbate) that 
is captured on a solid-phase surface (adsorbent) by either physical or chemical adsorption 
mechanisms. Carbon adsorbers are the most commonly used adsorption method. With carbon 
adsorption, the organic vapors are attracted to and physically held on granular activated carbon 
through intermolecular (van der Waals) forces. The two adsorber designs are fixed-bed and 
fluidized-bed. Fixed-bed adsorbers must be regenerated periodically to desorb the collected 
organics. Fluidized-bed adsorbers are continually regenerated. 46 


4-65 


Adsorption efficiency can be 95 percent for a modem, well-designed system. 
Removal efficiency depends upon the physical properties of the compounds in the offgas, the 
gas stream characteristics, and the physical properties of the adsorbent. Stream mass flow 
during regeneration, the temperature of the carbon bed, and organic concentration level in the 
stream must remain within a certain range to ensure optimal control efficiency. 46 Adsorbers are 
not recommended for vent streams with high VOC concentrations. 45 

Four types of combustion devices are identified for control of benzene emissions 
from process vents: flares, thermal oxidizers, boilers and process heaters, and catalytic 
oxidizers. A combustion device chemically converts benzene and other organics to C0 2 and 
water. If combustion is not complete, the organic may remain unaltered or be converted to 
another organic chemical, called a product of incomplete combustion. Combustion 
temperature and stream flow must remain within a certain range to ensure complete 
combustion. 46 


A flare is an open combustion process that destroys organic emissions with a 
high-temperature oxidation flame. The oxygen required for combustion is provided by the air 
around the flame. Good combustion is governed by flame temperature, residence time of the 
organics in the combustion zone, and turbulent mixing of the components to complete the 
oxidation reaction. There are two main types of flares: elevated and ground flares. A 
combustion efficiency of at least 98 percent can be achieved with such control. 46 

A thermal oxidizer is usually a refractory-lined chamber containing a burner (or 
set of burners) at one end. The thermal oxidation process is influenced by residence time, 
mixing, and temperature. Unlike a flare, a thermal oxidizder operates continuously and is not 
suited for intermittent streams. Because it operates continuously, auxiliary fuel must be used to 
maintain combustion during episodes in which the organic concentration in the process vent 
stream is below design conditions. Based on new technology, it has been determined that all 
new thermal oxidizers are capable of achieving at least 98 percent destruction efficiency or a 20 
parts per million by volume (ppmv) outlet concentration, based on operation at 870°C 
(1,600°F) with a 0.75-second residence time. 46 


4-66 


Industrial boilers and process heaters can be designed to control organics by 
combining the vent stream with the inlet fuel or by feeding the stream into the boiler or stream 
through a separate burner. An industrial boiler produces steam at high temperatures. A 
process heater raises the temperature of the process stream as well as the superheating steam at 
temperatures usually lower than those of an industrial boiler. Greater than 99 percent control 
efficiency is achievable with these combustion devices. 46 

By using catalysts, combustion can occur at temperatures lower than those used in 
thermal incineration. A catalytic oxidizer is similar to a thermal incinerator except that it 
incorporates the use of a catalyst. Combustion catalysts include platinum, platinum alloys, 
copper oxide, chromium, and cobalt. Catalytic oxidizers can achieve destruction efficiencies of 

98 percent or greater. 46 

Biofiltration is another type of VOC control. In biofiltration, process exhaust 
gases are passed through soil on compost beds containing micro organisms, which convert 
VOC to carbon dioxide, water, and mineral salts. 47 

Table 4-12 presents a comparison of the VOC control technologies (excluding 
combustion) that are discussed in this section. 47 

Process vents emitting benzene and other VOC that are discussed in Sections 4.1 
through 4.4 and in Section 5.0 are affected by one or more of the following six Federal 
regulations: 

1. “National Emission Standards for Organic Hazardous Air Pollutants from 
the Synthetic Organic Chemical Manufacturing Industry,” promulgated 
April 22, 1994. 48 

2. “National Emission Standards for Hazardous Air Pollutants from 
Petroleum Refineries,” promulgated August 18, 1995. 49 


4-67 


TABLE 4 12. COMPARISON OF VOC CONTROL TECHNOLOGIES 


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4-68 


another type of control 
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4-69 






3. “Standards of Performance for New Stationary Sources; Volatile Organic 
Compound (VOC) Emissions from the Synthetic Organic Chemical 
Manufacturing Industry (SOCMI) Air Oxidation,” promulgated 

July 1, 1994. 50 

4. “Standards of Performance for New Stationary Sources; Volatile Organic 
Compound (VOC) Emissions from the Synthetic Organic Chemical 
Manufacturing Industry (SOCMI) Distillation Operations,” promulgated 
July 1, 1994. 51 

5. “Standards of Performance for New Stationary Sources; Volatile Organic 
Compound (VOC) Emissions from the Synthetic Organic Chemical 
Manufacturing Industry (SOCMI) Reactor Processes,” promulgated 
July 1, 1994. 52 

6. “National Emission Standards for Benzene Emissions from Coke 
By-Product Recovery Plants, promulgated October 27, 1993.” 53 

In general, for the affected facilities subject to these six regulations, use of the recovery 
devices and combustion devices discussed above is required. Tables 4-10 and 4-11 present a 
summary of those controls and the required operating parameters and monitoring ranges needed 
to ensure that the required control efficiency is being achieved. 


4.5.2 Equipment Leak Emissions. Controls, and Regulations 


Equipment leak emissions occur from process equipment components whenever 
the liquid or gas streams leak from the equipment. Equipment leaks can occur from the 
following components: pump seals, process valves, compressor seals and safety relief valves, 
flanges, open-ended lines, and sampling connections. The following approaches for estimating 
equipment leak emissions are presented in the EPA publication Protocol for Equipment Leak 
Emission Estimates i 54 


Average emission factor approach; 
Screening ranges approach; 

EPA correlation approach; and 
Unit-specific correlation approach. 


4-70 



The approaches differ in complexity; however, greater complexity usually yields more accurate 
emissions estimates. 

The simplest method, the average emission factor approach, requires that the 
number of each component type be known. For each component, the benzene content of the 
stream and the time the component is in service are needed. This information is then 
multiplied by the EPA's average emission factors for the SOCMI shown in Table 4-13. 54 
Refinery average emission factors are shown in Table 4-14; marketing terminal average 
emission factors are shown in Table 4-15; and oil and gas production average emission factors 
are shown in Table 4-16. 54 This method is an improvement on using generic emissions 
developed from source test data, inventory data, and/or engineering judgement. However, this 
method should only be used if no other data are available because it may result in an 
overestimation or underestimation of actual equipment leak emissions. For each component, 
estimated emissions are calculated as follows: 

No. of 
equipment 
components 

To obtain more accurate equipment leak emission estimates, one of the more 
complex estimation approaches should be used. These approaches require that some level of 
emissions measurement for the facility’s equipment components be collected. These are 
described briefly, and the reader is referred to the EPA protocol document for the calculation 
details. 


X 

Weight % 
benzene 

X 

Component- 
specific 

X 

No. hr/yr in 
benzene service 


in the stream _ 


emission factor j 




The screening ranges approach (formerly known as the leak/no leak approach) is 
based on a determination of the number of leaking and non-leaking components. This 
approach may be applied when screening data are available as either "greater than or equal to 
10,000 ppmv" or as "less than 10,000 ppmv." Emission factors for these two ranges of 
screening values are presented in Table 4-17 for SOCMI screening; Table 4-18 for refinery 
screening, Table 4-19 for marketing terminal screening, and Table 4-20 for oil and gas 
production screening. 54 


4-71 










TABLE 4-13. SOCMI AVERAGE TOTAL ORGANIC COMPOUND EMISSION 
FACTORS FOR EQUIPMENT LEAK EMISSIONS 3 


Equipment Type 

Service 

Emission Factor 15 

lb/hr/source (kg/hr/source) 

Valves 

Gas 

Light liquid 

Heavy liquid 

0.01313 (0.00597) 

0.00887 (0.00403) 

0.00051 (0.00023) 

Pump seals c 

Light liquid 

Heavy liquid 

0.0438 (0.0199) 

0.01896 (0.00862) 

Compressor seals 

Gas 

0.502 (0.228) 

Pressure relief valves 

Gas 

0.229 (0.104) 

Connectors 

All 

0.00403 (0.00183) 

Open-ended lines 

All 

0.0037 (0.0017) 

Sampling connections 

All 

0.0330 (0.0150) 


Source: Reference 54. 

* The emission factors presented in this table for gas valves, light liquid valves, light liquid pumps, and 
connectors are revised SOCMI average emission factors. 
b These factors are for total organic compound emission rates. 

c The light liquid pump seal factor can be used to estimate the leak rate from agitator seals. 

The EPA correlation approach offers an additional refinement to estimating 
equipment leak emissions by providing an equation to predict mass emission rate as a function 
of screening value for a specific equipment type. The EPA correlation approach is preferred 
when actual screening values are available. Correlation operations for SOCMI, refinery, 
marketing terminals, and oil and gas production along with respective correlation curves are 
provided in Reference 54. 

The unit-specific correlation approach requires the facility to develop its own 
correlation equations and requires more rigorous testing, bagging, and analyzing of equipment 
leaks to determine mass emission rates. 

Appendix A of the EPA protocol document provides example calculations for 
each of the approaches described above. 


4-72 






TABLE 4-14. REFINERY AVERAGE EMISSION FACTORS 


Equipment type 

Service 

Emission Factor 
(kg/hr/source) a 

Valves 

Gas 

0.0268 


Light Liquid 

0.0109 


Heavy Liquid 

0.00023 

Pump seals b 

Light Liquid 

0.114 


Heavy Liquid 

0.021 

Compressor seals 

Gas 

0.636 

Pressure relief valves 

Gas 

0.16 

Connectors 

All 

0.00025 

Open-ended lines 

All 

0.0023 

Sampling connections 

All 

0.0150 


Source: Reference 54. 

1 These factors are for non-methane organic compound emission rates. 
b The light liquid pump seal factor can be used to estimate the leak rate from agitator seals. 

Although no specific information on controls of fugitive emissions used by the 
industry was identified, equipment components in benzene service will have some controls in 
place. Generally, control of fugitive emissions will require the use of sealless or double 
mechanical seal pumps and an inspection and maintenance program, as well as replacement of 
leaking valves and fittings. Typical controls for equipment leaks are listed in Table 4-21. 55 
Some leakless equipment is available, such as leakless valves and sealless pumps. 55 

Equipment leak emissions are regulated by the National Emission Standard for 
Equipment Leaks (Fugitive Emission Sources) of Benzene promulgated in June 6, 1984. 56 This 
standard applies to sources that are intended to operate in benzene service, such as pumps, 
compressors, pressure relief devices, sampling connection systems, open-ended valves or lines, 
valves, flanges and other connectors, product accumulator vessels, and control devices or 
systems required by this subpart. 


4-73 





TABLE 4-15. MARKETING TERMINAL AVERAGE EMISSION FACTORS 


Equipment Type 

Service 

Emission Factor 
(kg/hr/source) a 

Valves 

Gas 

1.3x1 O’ 5 


Light Liquid 

4.3xl0' 5 

Pump seals 

Gas 

6.5xl0' 5 


Light Liquid 

5.4x10"* 

Others (compressors and 

Gas 

1.2x10"* 

others) b 

Light Liquid 

1.3x10"* 

Fittings (connectors and 

Gas 

4.2x1 O' 5 

flanges) c 

Light Liquid 

8.0x1 O' 6 


Source: Reference 54. 


4 These factors are for total organic compound emission rates (including non-VOC such as methane and ethane). 
b The "other" equipment type should be applied for any equipment type other than fittings, pumps, or valves. 
c "Fittings" were not identified as flanges or non-flanged connectors; therefore, the fitting emissions were 
estimated by averaging the estimates from the connector and the flange correlation equations. 

Each owner or operator subject to Subpart J shall comply with the requirement of 
the National Emission Standard for Equipment Leaks promulgated in June 6, 1984. 57 The 
provisions of this subpart apply to the same sources mentioned above that are intended to 
operate in volatile hazardous air pollutant (VHAP) service. Benzene is a VHAP. 


The SOCMI New Source Performance Standards promulgated in 
October 18, 1983 58 also apply to equipment leak emissions. These standards apply to VOC 

emissions a f affected facilities that commenced construction, modification, or reconstruction 

after January 5, 1981. 


Equipment leak emissions from Coke by-product recovery plants are regulated 
by the National Emission Standard for Benzene Emissions from Coke By-Product Recovery 
Plants promulgated in September 14, 1989. 53 These standards apply to the same sources 
(equipment leak components) as indicated in Subpart J, and V of Part 61. 


.4-74 





TABLE 4-16. OIL AND GAS PRODUCTION OPERATIONS AVERAGE 

EMISSION FACTORS (kg/hr/source) 


Equipment Type 

Service 3 

Emission Factor 
(kg/hr/source) b 

Valves 

Gas 

4.5xl0' 3 


Heavy Oil 

8.4x1 O' 6 


Light Oil 

2.5xl0' 3 


Water/Oil 

9.8xl0' 5 

Pump seals 

Gas 

2.4x1 O' 3 


Heavy Oil 

NA 


Light Oil 

1.3xl0' 2 


Water/Oil 

2.4x1 O' 5 

Others c 

Gas 

8.8x10° 


Heavy Oil 

3.2x1 O' 5 


Light Oil 

7.5x1 O' 3 


Water/Oil 

1.4x1 O' 2 

Connectors 

Gas 

2.0x10-* 


Heavy Oil 

7.5x1c 6 


Light Oil 

2.1x10-* 


Water/Oil 

■ LlxlO - * 

Flanges 

Gas 

3.9x10"* 


Heavy Oil 

3.9xl0' 7 


Light Oil 

1.1x10"* 


Water/Oil 

2.9X10- 6 

Open-ended lines 

Gas 

2.0xlC 3 


Heavy Oil 

1.4x1 O'* 


Light Oil 

1.4x10' 3 


Water/Oil 

2.5x10-* 


Source: Reference 54. 

1 Water/Oil emission factors apply to water streams in oil service with a water content greater than 50 percent, 
from the point of origin to the point where the water content reaches 99 percent. For water streams with a water 
content greater than 99 percent, the emission rate is considered negligible. 
b These factors are for total organic compound emission rates (including non-VOC such as methane and ethane) 
and apply to light crude, heavy crude, gas plant, gas production, and off shore facilities. "NA" indicates that not 
enough data were available to develop the indicated emission factor. 
c The "other" equipment type was derived from compressors, diaphrams, drains, dump arms, hatches, instruments, 
meters, pressure relief valves, polished rods, relief valves, and vents. This "other" equipment type should be 
applied for any equipment type other than connectors, flanges, open-ended lines, pumps, or valves. 


4-75 







TABLE 4-17. SOCMI SCREENING VALUE RANGE TOTAL ORGANIC COMPOUND EMISSION FACTORS 

FOR EQUIPMENT LEAK EMISSIONS* 


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4-76 












TABLE 4-18. REFINERY SCREENING RANGES EMISSION FACTORS 


Equipment Type 

Service 

£10,000 ppmv 
Emission Factor 
(kg/hr/source) a 

<10,000 ppmv 
Emission Factor 
(kg/hr/source) a 

Valves 

Gas 

0.2626 

0.0006 

. 

Light Liquid 

0.0852 

0.0017 


Heavy Liquid 

0.00023 

0.00023 

Pump seals 6 

Light Liquid 

0.437 

0.0120 


Heavy Liquid 

0.3885 

0.0135 

Compressor seals 

Gas 

1.608 

0.0894 

Pressure relief valves 

Gas 

1.691 

0.0447 

Connectors 

All 

0.0375 

0.00006 

Open-ended lines 

All 

0.01195 

0.00150 


Source: Reference 54. 

1 These factors are for non-methane organic compound emission rates. 

b The light liquid pump seal factors can be applied to estimate the leak rate from agitator seals. 

The hazardous organic NESHAP (or HON) equipment leak provisions 
promulgated on April 22, 1994, affect chemical production processes. 59,60 The HON provisions 
apply to new and existing facilities and specify a control level of 90 percent. 


The petroleum refineries NESHAP equipment leak provisions promulgated on 
August 18, 1995 affects petroleum refinery process units. The petroleum refinery provisions 

apply to new and existing facilities. 


4.5.3 Storage Tank Emissions. Controls, and Regulations 


A possible source of benzene emissions from chemical production operations that 
produce or use benzene are storage tanks that contain benzene. Emissions from storage tanks 
include "working losses" and "breathing losses." Working losses are emissions that occur 
while a tank is being filled (filling the tank with liquid forces organic vapors out of the tank). 
Breathing losses are emissions that result from expansion due to temperature changes (a higher 


4-77 








TABLE 4-19. MARKETING TERMINAL SCREENING RANGES 


EMISSION FACTORS 


Equipment Type 

Service 

£ 10,000 ppmv 
Emission Factor 
(kg/hr/source) a 

<10,000 ppmv 
Emission Factor 
(kg/hr/source) a 

Valves 

Gas 

NA 

1.3x10' 5 


Light Liquid 

2.3x10' 2 

1.5x10' 5 

Pump seals 

Light Liquid 

7.7x1 O' 2 

2.4x10“ 

Others (compressors and 

Gas 

NA 

1.2x10“ 

others) 5 

Light Liquid 

3.4x10‘ 2 

2.4x10* 5 

Fittings (connectors and 

Gas 

3.4x10' 2 

5.9X10 -6 

flanges) c 

Light Liquid 

6.5xlO' 3 

7.2X10- 6 


Source: Reference 54. 

a These factors are for total organic compound emission rates (including non-VOC such as methane and ethane). 

"NA" indicates that not enough data were available to develop the indicated emission factors. 
h The "other" equipment type should be applied for any equipment type other than fittings, pumps, or valves. 
c "Fittings" were not identified as flanges or connectors; therefore, the fitting emissions were estimated by 
averaging the estimates from the connector and the flange correlation equations. 

ambient temperature heats the air inside the tank, causing the air to expand and forcing organic 
vapors out of the tank). The calculations to estimate working and breathing loss 
emissions from storage tanks are complex and require knowledge of a number of site-specific 
factors about the storage tank for which emissions are being estimated. Equations for 
estimating emissions of organic compounds from storage tanks are provided in the EPA 
document entitled Compilation of Air Pollutant Emission Factors (AP-42), Chapter 7. 33 


Benzene emissions from storage tanks may be reduced with control equipment 
and by work practices. Various types of control equipment may be used to reduce organic 
emissions, including (1) storing the liquid in a storage tank with a floating deck (i.e., an 
intemal-floating-roof tank or extemal-floating-roof tank), (2) equipping floating decks with 
additional devices to reduce emissions (e.g., applying sealing mechanisms around the perimeter 
of the floating deck, welding the deck seams, installing gaskets around openings and in closure 
devices on the floating deck), and (3) venting air emissions from a fixed-roof storage tank to a 
control device (e.g., a closed-vent system and a carbon adsorber, condenser, or flare). Work 


4-78 





TABLE 4-20. OIL AND GAS PRODUCTION OPERATIONS SCREENING RANGES 

EMISSION FACTORS 


Equipment Type 

Service 8 

£10,000 ppmv 
Emission. Factor 

(kg/hr/source) b 

10,000 ppmv 
Emission Factor 
(kg/hr/source) b 

Valves 

Gas 

9.8xl0' 2 

2.5xl0' 5 


Heavy Oil 

NA 

8.4x1 O' 6 


Light Oil 

8.7x 1C 2 

1.9x1 O' 5 


Water/Oil 

6.4x10‘ 2 

9.7x1 O' 6 

Pump seals 

Gas 

7.4x10' 2 

3.5x10-* 


Heavy Oil 

NA 

NA 


Light Oil 

1.0x10' 1 

5.1x10-* 


Water/Oil 

NA 

2.4x10' 5 

Others' 

Gas 

8.9x10' 2 

1.2x10-* 


Heavy Oil 

NA 

3.2xl0' 5 


Light Oil 

8.3xlC 2 

1.1x10-* 


Water/Oil 

6.9xl0' 2 

5.9x10' 5 

Connectors 

Gas 

2.6xl0' 2 

1.0x10' 5 


Heavy Oil 

NA 

7.5x1 O' 6 


Light Oil 

2.6xl0' 2 

9.7x1c 6 


Water/Oil 

2.8x10' 2 

4 

1.0x10' 5 

Flanges 

Gas 

8.2xl0' 2 

5.7X1C 6 


Heavy Oil 

NA 

3.9x1 O' 7 


Light Oil 

7.3x10' 2 

2.4x1c 6 


Water/Oil 

NA 

2.9x1 O' 6 

Open-ended lines 

Gas 

5.5xl0' 2 

1.5x10' 5 


Heavy Oil 

3.0x10' 2 

7.2X1C 6 


Light Oil 

4.4x10' 2 

1.4x10' 5 


Water/Oil 

3.0x10' 2 

3.5X10- 6 


Source: Reference 54. 

* Water/Oil emission factors apply to water streams in oil service with a water content greater than 50 percent, 
from the point of origin to the point where the water content reaches 99 percent. For water streams with a water 
content greater than 99 percent, the emission rate is considered negligible. 
b These factors are for total organic compound emission rates (including non-VOC such as methane and ethane) 
and apply to light crude, heavy crude, gas plant, gas production, and off shore facilities. "NA" indicates that not 
enough data were available to develop the indicated emission factor. 
c The "other" equipment type was derived from compressors, diaphrams, drains, dump arms, hatches, 

instruments, meters, pressure relief valves, polished rods, relief valves, and vents. This "other" equipment type 
should be applied for any equipment type other than connectors, flanges, open-ended lines, pumps, or valves. 


4-79 





TABLE 4-21. CONTROL TECHNIQUES AND EFFICIENCIES APPLICABLE TO 

EQUIPMENT LEAK EMISSIONS 


Equipment Component 
(Emission Source) 

Control Technique 

Percent Reduction 3 

Pump Seals: 



Packed and Mechanical 

Seal area enclosure vented 

100 


to a combustion device 



Monthly LDAR b 

69 


Quarterly LDAR 

45 

Double Mechanical 0 

N/A d 

— 

Compressors 

Vent degassing reservoir to 

100 


combustion device 


Ranges 

None available 

0 

Valves: 



Gas 

Monthly LDAR 

87 


Quarterly LDAR 

67 

Liquid 

Monthly LDAR 

84 


Quarterly LDAR 

61 

Pressure Relief Devices 

* 


Gas 

Monthly LDAR 

50 


Quarterly LDAR 

44 


Rupture Disk 

100 

Sample Connections 

Closed-purge sampling 

100 

Open-Ended Lines 

Caps on open ends 

100 


Source: Reference 55. 


If a negative reduction for a control technique was indicated, zero was used. 
b LDAR = Leak detection and repair, at a leak definition of 10,000 ppmv. 

Assumes the seal barrier fluid is maintained at a pressure above the pump stuffing box pressure and the system 
is equipped with a sensor that detects failure of the seal and/or barrier fluid system. 
d N/A - Not applicable. There are no VOC emissions from this component. 


4-80 





practices that reduce organic emissions include keeping manholes and other access doors 
gasketed and bolted unless in use. 


The control efficiencies achieved by the various types of control equipment 
vary. Storage tanks with internal or external floating roofs will have varying emission control 
efficiencies depending on the type of floating deck and seal mechanism used, as well as various 
other factors. The control efficiency achieved by closed-vent systems and control devices also 
varies, depending on the type and specific design of the control device used. For information 
on the control efficiencies associated with specific control devices, refer to Tables 4-10 and 
4-11. The control devices applicable to reducing process vent emissions listed in these tables 
are also applicable to storage tanks. 


Storage tanks containing benzene and other organic compounds are regulated by 
the four following Federal rules: 


1. “National Emission Standard for Benzene Emissions from Benzene 

Storage Vessels;” 61 

2. “Standards of Performance for Volatile Organic Liquid Storage Vessels 
for which Construction, Reconstruction, or Modification Commenced 
after July 23, 1984;” 62 

3. “National Emission Standards for Organic Hazardous Air Pollutants 
from the Synthetic Organic Chemical Manufacturing Industry for 
Process Vents, Storage Vessels, Transfer Operations, and 

Wastewater:” 63 and 

4. “National Emission Standards for Hazardous Air Pollutants from 
Petroleum Refineries.” 49 

In combination, these four regulations generally require new and existing 
facilities subject to the rules to store benzene in an intemal-floating-roof storage tank, an 
extemal-floating-roof storage tank, or a fixed-roof storage tank with a closed-vent system and 
control device that reduces emissions by 95 percent for a new facility, or 90 percent for an 
existing facility. Additionally, the four regulations include requirements for specific seal 
mechanisms and gaskets to be utilized on a floating roof, as well as certain work practices. 


4-81 


4.5.4 


Wastewater Collection and Treatment System Emissions, Controls, and 

Regulations 


A possible source of benzene emissions from chemical production operations 
that use benzene are wastewater collection and treatment systems that handle wastewater 
containing benzene. Benzene emissions from wastewater collection systems can originate from 
various types of equipment including wastewater tanks, surface impoundments, containers, 
drain systems, and oil-water separators. Emissions also originate from wastewater treatment 
systems. Equations for estimating emissions of organic compounds from wastewater collection 
and treatment systems are provided in the EPA document Compilation of Air Pollutant 
Emission Factors (AP-42), Chapter 4. M 

Two control strategies can be applied to benzene emissions from wastewater. 

The first control strategy is waste minimization through process modifications, modification of 
operating practices, preventive maintenance, recycling, or segregation of waste streams. The 
second control strategy is to reduce the benzene content of the wastewater.through treatment 
before the stream contacts ambient air. A complete strategy for reducing the benzene content 
of the wastewater includes: (1) suppression of emissions from collection and treatment system 
components by hard piping or enclosing the existing wastewater collection system up to the 
point of treatment, (2) treatment of the wastewater to remove benzene, and (3) treatment of 
residuals. Residuals include oil phases, condensates, and sludges from nondestructive 
treatment units. 65 This section will discuss the second control strategy of reducing benzene 
emissions by suppression ana treatment. 

The benzene emissions from wastewater collection and treatment systems can 
be controlled either by hard piping or by enclosing the transport and handling system from the 
point of wastewater generation until the wastewater is treated to remove or destroy the organic 
compounds. Suppression techniques can be broken down into four categories: collection 
system controls, roofs, floating membranes, and air-supported structures. These techniques can 
be applied to drain systems, tanks, containers, surface impoundments, and oil-water separators. 
Suppression of benzene emissions merely keeps the organic compounds in the wastewater until 


4-82 




they reach the next potential benzene emission source. Therefore, these techniques are not 
effective unless the benzene emissions are suppressed until the wastewater reaches a treatment 
device where the organic compounds are either removed or destroyed. Also, work practices, 
such as leak detection and repair, must be used to maintain equipment effectiveness. 65 

Treatment techniques that can be used to remove or destroy benzene are steam 
stripping and air stripping (removal) and biological treatment (destruction). Steam and air 
stripping accomplish removal by stripping benzene out of the wastewater into a gas stream, 
which must then be controlled and vented to the atmosphere. Biological treatment destroys 
benzene by using microorganisms to biodegrade the benzene in the process of energy and 
biomass production. 

Add-on controls serve to reduce benzene emissions by destroying or extracting 
benzene from gas phase vent streams before it is discharged to the atmosphere. Add-on 
controls are applicable to vents associated with collection and treatment covers, such as drain 
covers, fixed roofs, and air-supported structures, and with organic compound removal devices, 
such as air strippers and steam strippers. Add-on controls for benzene emissions are classified 
into four broad categories: adsorption, combustion, condensation, and absorption. The type of 
add-on control best suited for a particular wastewater emission source depends on the size of 
the source and the characteristics of the wastewater in the source. 65 

The control efficiencies associated with the various types of suppression, 
treatment, and add-on control equipment vary, Estimating the control efficiency of emissions 
suppression techniques for wastewater collection systems (e.g., water seals, covers, floating 
roofs, and submerged fill pipes) is complex, and equations for estimating emissions from these 
sources are not readily available. The control efficiency associated with use of a fixed-roof or 
gasketed cover and a closed-vent system routed to a control device would be equivalent to the 
efficiency achieved by the control device. Refer to Tables 4-10 and 4-11 for a listing of control 
devices applicable to wastewater systems. Additionally, the control efficiencies associated 
with steam and air strippers and biological treatment units vary, depending on the design of the 
systems. Refer to the discussion below for the specific control efficiencies associated with 


4-83 


steam strippers and biological treatment units that would be designed to comply with existing 
Federal regulations. 

Wastewater streams containing benzene are Federally regulated by the following 

rules: 


1. “National Emission Standard for Benzene Waste Operations;” 66 

2. “National Emission Standards for Organic Hazardous Air Pollutants 
from the Synthetic Organic Chemical Manufacturing Industry for 
Process Vents, Storage Vessels, Transfer Operations, and Wastewater” 
(HON); 63 and 

3. “National Emission Standards for Hazardous Air Pollutants at 
Petroleum Refineries.” 49 


The rules regulate benzene emissions from wastewater collection and treatment 
systems, and apply to new and existing facilities. Chemical production processes subject to the 
regulations would be required to apply many of the controls specified above for both 
wastewater collection and waste water treatment systems. 


The rules require specific suppression equipment (e.g., roofs) and work 
practices (e.g., leak detection and repair) rather than specifying a suppression control efficiency 
that must be achieved. For add-on control devices (e.g., incinerators, adsorbers) to destroy 
organics vented from collection and treatment equipment, both rules require 95 percent 

efficiency. 


For treatment, the National Emission Standard for Benzene Waste Operations 66 
and the National Petroleum Refinery NESHAP 49 do not require specific treatment equipment. 
Instead, the rule requires the treatment process to achieve either removal or destruction of 
benzene in the waste system by 99 percent, or removal of benzene to less than 10 parts per 
million by weight (ppmw). However, the technology basis for the 99 percent efficiency 
standard is steam stripping. 


4-84 


The HON offers several different wastewater treatment compliance options. 
These options include concentration-based limits, pollutant reduction percentages, and an 
equipment standard. The equipment standard is a steam stripper with specific design criteria 
that would result in a 99 percent reduction in benzene emissions. The HON also allows 
facilities to comply with the treatment standard by using biological treatment units that achieve 
a 95 percent reduction of total organic hazardous air pollutants in the wastewater. (Benzene is 
one of the hazardous air pollutants). 

4.5.5 Product Loading and Transport Operations Emissions. Controls, and 

Regulations 

Although pipeline transfer of raw materials and products is widely used in the 
different industries, shipment by tank cars, tank trucks, ships, and barges is also common. The 
product loading and transportation of chemicals and petroleum liquids represent potential 
sources of evaporation losses. 

Emissions from the above sources are due to loading losses, ballasting losses, 
and transit losses. Refer to Section 6.3 (Gasoline Marketing) of this document for information 
on emission factors and equations to estimate emissions from loading and transport operations, 
as well as information on control technology. 

The HON regulates organic hazardous air pollutants (HAP) emissions from 
proauci loading ana transport operations/ 0 * 1 The National Emission Standard for Benzene 
Emissions from Benzene Transfer Operations also regulates benzene transfer emissions. 67 


4-85 




































































■ 

- 
































































SECTION 5.0 

EMISSIONS FROM MAJOR USES OF BENZENE 


The largest portion of benzene produced is used in the production of 
ethylbenzene/styrene. Other major chemicals for which benzene is used as a feedstock include 
cyclohexane, cumene, phenol, nitrobenzene, and linear alkylbenzene. For each of these 
emission sources, the following information is provided in the sections below': (1) a brief 
characterization of the national activity in the United States, (2) a process description, 

(3) benzene emissions characteristics, and (4) control technologies and techniques for reducing 
benzene emissions. In some cases, the current Federal regulations applicable to the source 
category are discussed. 

Emission factors are presented, as available. The reader is advised to contact 
the specific source in question to verify the nature of the process, production volume, and 
control techniques used before applying any of the emission factors presented in this report. 

Other minor chemicals where benzene is used as a feedstock include resorcinol 

benzophenone, hydroquinone, anthraquinone, biphenyl, and benzene sulfonic acid. 68 These 
chemical processes are discussed briefly in this section. Although benzene has been used in the 
past as a feedstock in the production of maleic anhydride, all capacity for producing maleic 
anhydride in the United States is now n-butane based; therefore, the process for producing 
maleic anhydride from benzene is not included in this section. 


5-1 


5.1 


ETHYLBENZENE AND STYRENE PRODUCTION 


Ethylbenzene is a liquid at standard conditions, with a boiling point of 277 °F 
(136°C) and a vapor pressure of 1,284 Pa (0.0126 atm). 69 About 50 percent of the U.S. 
production of benzene is used to produce ethylbenzene. The ethylbenzene industry is closely 
tied to the styrene industry because styrene is produced exclusively from ethylbenzene. There 
can be approximately a 0.3 percent by weight carry-over of benzene into ethylbenzene and 
styrene. 9 Additionally, some benzene is reformed in the production of styrene. Ethylbenzene 
production processes and uses thereby constitute a major potential source of benzene 
emissions, particularly because styrene production is anticipated to experience continued 
growth. Ethylbenzene demand is expected to show growth of only 2.5 to 3.5 percent per year 
over the next several years. 70 

Ethylbenzene is used almost exclusively to produce styrene. Some ethylbenzene 
is used as a solvent (often replacing xylene) and in the production of some dyes. 71 Total 
ethylbenzene production capacity is currently 13,874 million pounds per year (lb/yr) (6,293 
kg/yr). 11 Approximately 95 percent of this capacity is based on benzene alkylation, with the 
remainder based on extraction from mixed xylene streams. Most styrene is produced by two 
methods: hydrogenation of ethylbenzene (89 percent) and peroxidation of ethylbenzene with 
subsequent hydration (11 percent). The latter process can also co-produce propylene oxide. A 
third process, converting ethylbenzene isothermally to styrene, was developed in Europe. To 
date, no U.S. facilities report using this method. 

Another method that co-produces both ethylbenzene and styrene has been 
patented. 72 In this process, toluene and light alkanes other than ethane are reacted at 1,832 to 
2,192 °F (1,000 to 1,200°C) and then gradually cooled to produce an 80 percent 
ethylbenzene/12 percent styrene product with a mass of about 25 percent by weight of the 
toluene reactant. These products can be separated by distillation, and the ethylbenzene either 
recycled, sold, or converted to styrene by another process-dehydrogenation or peroxidation. 
This process is not reported to be in use at this time. 


5-2 


Table 5-1 lists U.S. producers of ethylbenzene and styrene. 11,69,73 Most facilities 
produce both ethylbenzene and styrene on site, thus reducing shipping and storage. Only one 
styrene production site does not have ethylbenzene production capacity. Four ethylbenzene 
production sites do not have styrene production capacity. Ethylbenzene from mixed xylene 
separation is generally shipped or supplemented with another ethylbenzene source for styrene 
production. Only one site uses the peroxidation process to produce styrene. Table 5-1 also 
gives the latest facility capacity. 

5.1.1 Process Description for Ethylbenzene and Stvrene Production Using Benzene 

Alkylation and Ethylbenzene Dehydrogenation 

Most ethylbenzene production is integrated with the dehydrogenation process to 
produce styrene; therefore, these processes are described together. The primary reactions are 
(1) catalytic alkylation of benzene with ethylene to produce ethylbenzene, and (2) catalytic 
dehydrogenation of ethylbenzene to produce styrene. 

A process flow diagram including the basic operations that may be used in the 
production of ethylbenzene by benzene alkylation with ethylene is shown in Figure 5-1. 14,74 

The first step in the process is the drying of benzene to remove water from both 
feed and recycled benzene. An emission source in this process is the vent from the benzene 
drying column (Vent B). 69 

The dry benzene (Stream 1) is fed to the alkylation reactor along with ethylene, 
aluminum chloride catalyst, and recycled polyethylbenzenes. The reactor effluent (Stream 2) 
goes to a settler, where crude ethylbenzene is decanted and the heavy catalyst-complex layer is 
recycled to the reactor. Any inert gases fed with the ethylene or produced in the alkylation 
reactor, along with some unreacted benzene, other organics, and hydrogen chloride, are 
exhausted from the reactor or from the treating section (Vent A). Reactor vent gas is generally 
routed through a condenser and scrubbers in the alkylation reaction section (not shown on the 


5-3 






TABLE 5 1. U.S. PRODUCERS OF ETHYLBENZENE AND STYRENE 


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5-5 


Aluminum Chlorid* Catalyst Poly.thylb.nz.n* R*cycl*d B.nz.n* 



5-6 


Benzene Alkylation with Ethylbenzene 


























































figure) to recover aromatics and to remove hydrogen chloride (HC1) before the remaining inert 
gases are vented. 69 

The crude ethylbenzene (Stream 3) from the settler is washed with water and 
caustic to remove traces of chlorides and then fed to the ethylbenzene purification section. The 
crude ethylbenzene contains 40 to 55 percent benzene, 10 to 20 percent poly ethylbenzene 
(PEB), and high-boiling point materials. The first step in purification is separation of recycled 
benzene (Stream 4) from the crude ethylbenzene in the benzene recovery column. In the 
second step, the product ethylbenzene (Stream 5) is separated from the heavier hydrocarbons in 
the ethylbenzene recovery column. The heavier hydrocarbons are distilled in the 
polyethylbenzene column to separate the polyethylbenzenes, which are recycled (Stream 7), 
from the residue oil. 69 Emission points in the purification section include vents from the 
benzene and ethylbenzene recovery columns (Vent C and D, respectively) and the 
poly ethylbenzene column (Vent E). 69 

Fresh ethylbenzene (Stream 6) from the ethylbenzene purification section is 
combined with recycled ethylbenzene (Stream 8) from the styrene purification section at the 
integrated styrene plant and is stored for use as an intermediate for making styrene. 69 Other 
emission points from the process including storage tanks, are shown in Figure 5-1. 


pi 


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A process flow diagram including the basic operations that may be used in the 

styrene by ethylbenzene dehydrogenation is shown in Figure 5-2. 69 74 


Fresh ethylbenzene from the ethylbenzene purification section (ethylbenzene 
plant) is combined with recycled ethylbenzene (Stream 1) from the styrene purification section. 
The purified ethylbenzene is preheated in a heat exchanger. The resultant vapor (Stream 2) is 
then mixed continuously with steam at 1,310°F (710°C) in the dehydrogenation reactor, which 
contains one of several catalysts. The reaction product (Stream 3) then exits through the heat 
exchanger and is further cooled in a condenser, where water and crude styrene vapors are 
condensed. 


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Ethylbenzene Dehydrogenation 






































































The hydrogen-rich process gas is recovered and used as a fuel (Stream 7) and 
the process water is purified in a stripper and recycled to the boiler. The remaining crude 
styrene liquid (Stream 6) goes to a storage tank. Benzene and toluene (Stream 8) are removed 
from the crude styrene in the benzene/toluene column. They are then typically separated by 
distillation. The toluene is sold and the benzene is returned to ethylbenzene production section 
(Stream 10), or it may also be sold. Next, the ethylbenzene column removes ethylbenzene, 
which is directly recycled (Stream 1). Tars are removed and the product styrene (Stream 9) 
emerges from the styrene finishing column. In some facilities, an 

ethylbenzene/benzene/toluene stream is separated from the crude styrene initially and then 
processed separately. 


Emission points in this process include vents from the columns for the styrene 
purification section between the separator and the recovery sections. These include the 
benzene toluene column (Vent A), the ethylbenzene recycle column (Vent B) and the 
emergency vent in the styrene finishing column (Vent C). Other emission points from the 
process including storage tanks and barge loading are shown in Figure 5-2'. 

5.1.2 Process Description for Ethylbenzene Production from Mixed Xylenes 


Ethylbenzene can also be extracted from mixed xylene streams. 

Proportionately, however, very little ethylbenzene is produced in this fashion. The two major 
sources of ethylbenzene containing xylenes are catalytic reformate from refineries, and 

pyrolysis gasoline from ethylene production (see process description for ethylene production in 
Section 4.3). The amount of ethylbenzene available is dependent on upstream production 
variables. The ethylene separation occurs downstream of the benzene production. For this 
reason, the ethylbenzene produced by this process is not considered a source of benzene 
emissions. Instead, benzene emissions from the entire process train are considered to be 
emissions from benzene production and are included elsewhere in this document (Section 4.0). 


5-9 



When combined with the dehydrogenation process previously described to 
produce styrene (Figure 5-2), the process is similar except that the benzene recycling 
(Stream 10 in Figure 5-2) cannot be reused directly. 

5.1.3 Process Description for Styrene Production from Ethylbenzene 

Hvdroperoxidation 

Presently, only one U.S. facility uses the hydroperoxidation process to produce 
styrene. Figure 5-3 shows a process flow diagram. The four major steps are described below. 

Ethylbenzene (Stream 1) is oxidized with air to produce ethylene hydroperoxide 
(Stream 2) and small amounts of a-methyl-benzyl alcohol and acetophenone. The exit gas 
(principally nitrogen) is cooled and scrubbed to recover aromatics before venting. Unreacted 
ethylbenzene and low-boiling contaminants are removed in an evaporator. Ethylbenzene is 
then sent to the recovery section to be treated before reuse. 

Ethylbenzene hydroperoxide (Stream 3) is combined with propylene over a 
catalyst mixture and high pressures to produce propylene oxide and acetophenone. Pressure is 
then reduced and residual propylene and other low-boiling compounds (Stream 4) are separated 
by distillation. The vent stream containing propane and some propylene can be used as a fuel. 
Propylene is recycled to the epoxidation reactor. The crude epoxidate (Stream 5) is treated to 
remove acidic impurities and residual catalyst material and the resultant epoxidate stream is 
distilled to separate the propylene oxide product for storage. 

Residual water and propylene are recycled to the process train and liquid 
distillate is recovered as a fuel. The organic layer is routed (Stream 6) to the ethylbenzene and 
a-methyl-benzyl alcohol recovery section. Distillation removes any remaining ethylbenzene. 
Organic waste streams are separated from the a-methyl-benzyl alcohol and acetophenone 
organic waste liquids are used as fuel. 


5-10 





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Figure 5-3. Ethylbenzene Hydroperoxidation Process Block Diagram 













































































The mixed stream of a-methyl-benzyl alcohol and acetophenone (Stream 7) is 
then dehydrated over a solid catalyst to produce styrene. Residual catalyst solids and 
high-boiling impurities are separated and collected for disposal. The crude styrene goes to a 
series of distillation columns, where the pure styrene monomer product is recovered. The 
residual organic stream contains crude acetophenone, catalyst residue, and various impurities. 
This mixture is treated under pressure with hydrogen gas to convert the acetophenone to 
a-methyl-benzyl alcohol. Catalyst waste is separated from the a-methyl-benzyl alcohol, which 
is returned to the recovery section for processing and reuse. Hydrogen and organic vapors are 
recovered for use as fuel. 

5.1.4 Process Description for Stvrene Production bv an Isothermal Process 

Ethylbenzene may also be converted to styrene by an isothermal process 
(Figure 5-4). Liquid ethylbenzene is vaporized by condensing steam in a heat exchanger 
(Stream 1). Process steam (Stream 2) is then introduced into the ethylbenzene stream and the 
feed mixture is superheated (Stream 3) before it enters the molten-salt reactor (Stream 4) 

(see Figure 5-4). 75 

In the reactor, the ethylbenzene/steam mixture passes through the tubes, where 
it comes into contact with the catalyst and is dehydrogenated. Heat for the dehydrogenation 
reaction is supplied by molten salt (preferably a mixture of sodium carbonate, lithium 
carbonate, and potassium carbonate) surrounding the tubes (Stream 5). The reactor is 
maintained at a uniform wall temperature by circulating the molten-salt mixture through the 
heat exchanger of a fired heater (Stream 6). 75 

The reaction products are cooled and condensed in a separator (Stream 7). The 
liquid phase is a mixture of organic products: styrene, unreacted ethylbenzene, and small 
quantities of benzene, toluene, and high-boiling compounds. Styrene (Stream 8) is separated 
from the other liquid constituents, which then are recovered and recycled. 75 


5-12 



Steam 

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5-13 



















































































The gas phase from the condensation step in the separator consists mainly of 
hydrogen, with small quantities of C0 2 , CO, and methane.- After these gases are compressed, 
they are cooled. Condensible products from this fmal cooling stage are then recovered and 
recycled to the separator. When hydrogen-rich offgas is used as fuel for the heater of the 
molten-salt reactor, the fuel requirement for this stage of the process is zero. 75 

5.1.5 Benzene Emissions from Ethylbenzene and Stvrene Production via Alkylation 

and Dehydrogenation 

Emission Estimates from Ethylbenzene Production and Dehydrogenation to 
Styrene 

Emission factors have been developed based on an uncontrolled 300-million- 
kg/yr capacity integrated ethylbenzene/styrene production plant. Major process emission 
sources are the alkylation reactor area vents (Vent A in Figure 5-1). atmospheric and pressure 
column vents (Vents B, C, and D in Figure 5-1), vacuum column vents (Vent B in Figure 5-2), 
and the hydrogen separation vent (Stream 7 in Figure 5-2). Emission factors from these 
sources are given in Table 5-2. 69,74 The first four process vent streams in Table 5-2 are low- 
flow, high-concentration streams. The hydrogen separation stream (Stream 7 in Figure 5-2) is 
high-flow, low-concentration. Other emission sources listed in Table 5-2 include storage 
losses and shipment losses (Vent G). Fugitive emissions from valves and other equipment 
leaks are not indicated in Figure 5-1 or 5-2. 

Reactor area vents remove various inerts plus entrained aromatics (benzene). 
Inerts include nitrogen or methane used in pressure control, unreacted ethylene, reaction 
byproducts, and ethylene feed impurities. In typical plants using liquid-phase aluminum 
chloride catalyst with high-purity ethylene, vent streams are usually cooled and scrubbed to 
recover aromatics. In plants using the newer solid support catalysts of the UOP or 
Mobil/Badger process, reactor vent flow rates are very high because of the low-purity ethylene 
feed. Process economics requires that these vent gases be burned as fuel. 


5-14 




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styrene 















Atmospheric and column vents remove non-combustibles in the column feeds, 
light aliphatic hydrocarbons, and any entrained aromatics. The benzene drying column also 
removes impurities in the benzene feed. Most emissions occur in the first column of the 
distillation train (benzene recovery column in Figure 5-1). 

Vacuum column vents remove air that leaks into the column, light hydrocarbons 
and hydrogen formed in dehydrogenation, non-combustibles in the column feed, and entrained 
aromatics. Most emissions occur on the benzene/toluene column (vent A in Figure 5-2). 
Uncontrolled distillation vents emit 4.2xl0' 3 lb hydrocarbons/lb styrene (4.2xl0' 3 kg 
hydrocarbons/kg styrene) in one plant where the hydrocarbons are benzene and toluene. 
Another condenser controlled vent emits 0.4x1 O' 3 lb benzene/lb styrene (0.4x1 O' 3 kg 
benzene/kg styrene). 9 

Following dehydrogenation, a hydrogen-rich gas (Stream 4 in Figure 5-2) 
containing methane, ethane, ethylene, C0 2 , CO, and aromatics is normally cooled and 
compressed to recover aromatics. The stream should be vented to the atmosphere (Vent E in 
Figure 5-2) only during startup, shutdown, and recovery section compressor outages. Some 
plants may also vent this stream to a flare. Flares are an efficient (99 percent) emission control 
only when flare diameter and gas flow are closely matched for optimum turbulence and 
mixing. Emissions can be better controlled when the stream is routed to a manifold and 
burned with other fuels. 

Stripper vents have been reported to emit 0.032 lb ethylbenzene/lb styrene (32 g 
ethylbenzene/kg styrene). 9 This corresponds to 9.6x1 O' 6 lb benzene/lb styrene (9.6x1 O' 3 g 
benzene/kg styrene). Benzene in shipping and storage (Vent F in Figure 5-1) must also be 
considered as a source if benzene is not produced on site (in which case these emissions would 
be considered pan of the benzene production process). 


5-17 


Benzene Emissions from Styrene Production Using Ethylbenzene 
Hydroperoxidation 

Only one U.S. facility currently reports using this method. Emission estimates 
presented in this section are based on a capacity of 1200 million lb styrene/yr (544 million kg 
styrene/yr). 


The three main process emission sources are the ethylbenzene oxidation reactor 
vent (A in Figure 5-3), the propylene recycle purge vent (B), and the vacuum column vents (C) 
and (D). Propane vapor (B) is considered a fuel if it is not vented to the atmosphere. Of these 
sources, only the vacuum vents are large benzene emitters. These emissions result from 
benzene impurities in the ethylbenzene feed, which may result in minor side reactions in the 
process train. 


The ethylbenzene oxidation reactor vent (A) releases CO, light organics, 
entrained aromatics with nitrogen, oxygen, and C0 2 . The vent gas is scrubbed with oil and 
water for a 99 percent removal efficiency for organics. The resulting vent stream contains 
approximately 35 ppm benzene (0.11 mg benzene/1) or 15.9 lb benzene/hr (7.2 kilograms 
benzene per hour [kg/hr]). 74 

The propylene recycle vent (B) releases propane, propylene, ethane, and other 
impurities. No flow volume data are available but, based on a similar procedure in high-grade 
propylene production, this stream is a high-Btu gas and would be used as a fuel. No 
significant benzene emissions are expected. 74 

The ethylbenzene hydroperoxidation process contains numerous vacuum 
columns and evaporators. Vents on these operations (C-l to C-3) release inerts and light 
organics dissolved in the column feeds, nitrogen used for process pressure control, and 
entrained aromatics. A combined vent flow is reported to be 264,200 gal/hr (l.OxlO 6 1/hr) 
containing about 60 lbs benzene/hr (27 kg benzene/hr). 74 


5-18 


The dehydrogenation vent (D in Figure 5-3) may be an emergency pressure vent 
similar to the separation vent (C in Figure 5-2). No specific information is available on 
storage, transport, or fugitive emissions for this process. 

5.1.6 Control Technology for Ethvlbenzene/Stvrene Processes 

Control methods for the two ethylbenzene/styrene processes in use in the United 
States include condensation, adsorption, flaring, and combustion in boilers or other process 
heaters. Controls for fugitive emissions from storage tanks, equipment leaks, and others 
include the use of floating-roof tanks and leak detection/correction programs. No information 
is available on control methods specific to the two processes mentioned in this report but not in 
use in the United States. 

Condensers may be used to control benzene emissions associated with 
ethylbenzene/styrene production. The control efficiency of a condenser is determined by the 
temperature and pressure at which the condenser operates and by the concentration and vapor 
pressure of the organics in the vent stream. At typical pressures of 1 to 3 atmospheres and coil 
temperatures of 36 to 41 °F (2 to 5°C), condensers can achieve 80 to 90 percent benzene 
reduction when used on vent streams at 70 to 100 percent saturation in benzene at 104 to 
122 °F (40 to 50°C). 74 Higher efficiencies become prohibitively expensive. 

Condensers have limited use in handling high-volume streams, short duration 
emergency releases, or cyclic releases such as from the hydrogen separation vent. 

Furthermore, condensers are inefficient at low saturations such as with the alkylation reactor 
vents and the column vents of Figure 5-1. 

In an ethylbenzene/styrene plant, a packed tower can be used to remove 
benzene. PEB and various ethylbenzene produced during benzene alkylation are good 
absorbers of benzene and are normally recycled. This system is unsuitable, however, for 
handling high-volume or intermittent releases of gases beyond the tower design capabilities. 


5-19 



Absorption systems can maintain 80 to 99 percent benzene removal efficiencies for both 
saturated and unsaturated benzene streams, depending on the tower design and operating 
variables. 

Flare systems can control some streams for which condensation or absorption is 
not suitable. Flares can efficiently handle highly saturated streams such as ffom the alkylation 
vents. They can also control upset releases and other irregular releases, although efficiency 
can be variable. The major difficulty here occurs in manifolding. High-nitrogen or other low- 
or non-combustible gases may also be problematic. Consequently, there are no conclusive data 
on flare efficiency. Limited data show benzene destruction efficiencies ranging from 60 to 
99 percent. A properly designed flare system must account for a range of flow and gas 
composition as well as the potential for explosion. 

Use of vent gases as a fuel combined with regular process fuel is advantageous 
because vent flow variations can be better accounted for. Also, better gas/air mixing occurs 
along the entire flare front. As with flares, however, manifolding to ensure optimal 
combustion characteristics is the major technical problem. Process pressure variations and the 
possibility of emergency releases are complicating factors. 

5.2 CYCLOHEXANE PRODUCTION 

About 15 percent of the U.S. supply of benzene is used to produce 
cyclohexane. 10 Table 5-3 lists the location and current capacity for U.S. cyclohexane 
producers. 11 Two basic methods are used to produce cyclohexane: hydrogenation of benzene 
and petroleum liquid separation. Most of the cyclohexane produced domestically is produced 
through hydrogenation of benzene. The following discussions of these two processes are taken 
from Reference 76. 


5-20 


TABLE 5-3. U.S. PRODUCERS OF CYCLOHEXANE 


Company 

Location 

Annual Capacity 
millions of gal (1) 

Chevron Chemical Company 

Port Arthur, TX 

38 (144) 

Phillips Petroleum Company 



Specialty Chemicals Branch 

Borger, TX 

35 (132) 

Olefins and Cyclics Branch 

Sweeny, TX 

' 90(341) 

Phillips Puerto Rico Core, Inc. 

Guayama, PR 

100 (379) 

Texaco Chemical Company 

Port Arthur, TX 

75 (284) 

CITGO Petroleum Corporation 

Corpus Christi, TX 

30(114) 

TOTAL 

368 (1,393) 


Source: Reference 11. 


Note: This list is subject to change as market conditions change, facility ownership changes, plants are closed, 
etc. The reader should verify the existence of particular facilities by consulting current lists and/or the 
plants themselves. The level of benzene emissions from any given facility is a function of variables such 
as capacity, throughput and control measures, and should be determined through direct contacts with plant 
personnel. These plant locations and capacities were current as of January 1, 1993. 

5.2.1 Process Description for Cyclohexane Production via Benzene Hydrogenation 

Figure 5-5 shows a model flow diagram for the manufacture of cyclohexane by 
benzene hydrogenation. 76 High-purity benzene (Stream 1) is fed to the catalytic reactors in 
parallel and hydrogen (Stream 2) is fed into the reactors in series. Part of the cyclohexane 

separated in the flash separator is recycled (Stream 3) and fed to the reactors in series. 
Recycling helps to control the reactor temperature, because the reaction is highly exothermic. 
The temperature is also controlled by generating steam, which is used elsewhere in the 
petrochemical complex. Both platinum and nickel catalysts are used presently to produce 
cyclohexane. 


5-21 







Uquldx-Byproduct to 

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5-22 


Figure 5-5. Process Flow Diagram for Cyclohexane Production Using the Benzene 

Hydrogenation Process 






































































After leaving the flash separator, the cyclohexane (Stream 4) is sent to a 
distillation column (stabilizer) for removal of methane, ethane, other light hydrocarbons, and 
soluble hydrogen gas from the cyclohexane product. These impurities (Stream 6) are routed to 
the fuel-gas storage system for the facility and used as fuel in process heaters. Cyclohexane 
(Stream 5) purified in the stabilizer may be greater than 99.9 percent pure. The residual 
benzene content is typically less than 0.0042 lb/gal (500 mg/1). This pure product is stored in 
' large tanks prior to shipment. 

Gas from the flash separator, largely hydrogen, is not pure enough for direct 
reuse. Therefore, the stream (8) is purified before being recycled to (Stream 2) the reactor. 
Typical processes used for hydrogen purification are absorption and stripping of the hydrogen 
gas and cryogenic separation. Some plants use a combination of the two processes. Organic 
liquids (Stream 10) that are separated from the hydrogen in the hydrogen purification unit are 
sent to other petroleum processing units in the petrochemical complex. The separated gases 
(Stream 9) are used as fuel gas. 

Depending on the type of hydrogen purification used, inert impurities present in 
the gas from the flash separator can be purged from the system before the gas enters the 
hydrogen purification equipment. This stream (7) is sent to the fuel gas system. 

5.2.2 Benzene Emissions from Cyclohexane Production via Benzene Hydrogenation 

There are no process emissions during normal operation. 76 During shutdowns, 
individual equipment vents are opened as required during final depressurization of equipment. 
Except for the feed streams, the concentration of benzene in the process equipment is low; 
therefore, few or no benzene emissions would be expected during a shutdown. 76 

Equipment leak emissions from process pumps, valves, and compressors may 
contain benzene or other hydrocarbons. Storage of benzene (Vent A in Figure 5-5) may also 
contribute to benzene emissions. 


5-23 



Other potential sources of emissions are catalyst handling (B) and absorber 
wastewater (C) (when an aqueous solution is used to purify the recycled hydrogen). Caution is 
taken to remove the organic compounds from the spent catalyst before it is replaced. The 
spent catalyst is sold for metal recovery. 76 

5.2.3 Process Description for Cyclohexane Production via Separation of Petroleum 

Fractions 

Cyclohexane may also be produced by separation of select petroleum fractions. 
The process used to recover cyclohexane in this manner is shown in Figure 5-6. 76 A petroleum 
fraction rich in cyclohexane (Stream 1) is fed to a distillation column, in which benzene and 
methylcyclopentane are removed (Stream 2) and routed to a hydrogenation unit. The bottoms 
(Stream 3) from the column containing cyclohexane and other hydrocarbons are combined with 
another petroleum stream (4) and sent to a catalytic reformer, where the cyclohexane is 
convened to benzene. The hydrogen generated in this step may be used in the hydrogenation 
step or used elsewhere in the petrochemical complex. 

The benzene-rich stream (5) leaving the catalytic reformer is sent to a distillation 
column, where compounds that have vapor pressure higher than benzene (pentanes, etc.) are 
removed (Stream 6) and used as byproducts. The benzene-rich stream (7) that is left is sent to 
another distillation column, where the benzene and methylcyclopentane (Stream 8) are 
removed. The remaining hydrocarbons (largely dimethylpentanes) are used elsewhere in the 
petrochemical complex as byproducts (Stream 9). 

Stream 8 (benzene and methylcyclopentane) is combined with Stream 2 and sent 
to a hydrogenation unit (Stream 10). Hydrogen is fed to this unit and the benzene is converted 
to cyclohexane. Isomers of cyclohexane, such as methylcyclopentane, are converted to 
cyclohexane in an isomerization unit (Stream 11) and the effluent from this equipment 
(Stream 12) is separated in a final distillation step. Pure cyclohexane (Stream 14) is separated 
from isomers of cyclohexane (Stream 13) and compounds with lower vapor pressures 
(Stream 15). 


5-24 





Hexanes 

Methylcyclopentane 



diU-«f-M1d-8S00*6 


3 

O 

CO 


5-25 


Note: The stream numbers on the figure correspond to the discussion in the text for 
this process. Letters correspond to potential sources of benzene emissions. 

Figure 5-6. Process Flow Diagram for Cyclohexane from Petroleum Fractions 










































5.2.4 


Benzene Emissions from Cyclohexane Production via Separation of Petroleum 
Fractions 


There are no process emissions during normal operation. 76 During emergency 
shutdowns, individual equipment vents are opened as required. 

Equipment leaks can be sources of benzene, cyclohexane, methane, or other 
petroleum compound emissions. Leaks from heat exchangers into cooling water or steam 
production can be a potential fugitive loss. Equipment leak losses have special significance 
because of the high diffusivity of hydrogen at elevated temperatures and pressures and the 
extremely flammable nature of the liquid and gas processing streams. 77 No specific emission 
factors or component counts (valves, flanges, etc.) were found for benzene associated with 
equipment leak emissions at these plants. 

A potential source of benzene emissions is catalyst handling. Special efforts are 
made to remove the organic compounds from the spent catalyst before it is replaced. The 
spent catalyst is sold for metal recovery. 76 No emission factors were found for benzene as 
related to catalyst handling. 

5.3 CUMENE PRODUCTION 

Tn the United States, all commercial cumene is produced by the reaction of 
benzene with propylene. Typically, the catalyst is phosphoric acid, but sulfuric acid or 
aluminum chloride may be used. Additionally, various new processes based on solid zeolite 
catalysts were introduced during 1993; however, information about these new processes is 
limited, and they are not discussed in this section. The location and capacities of U.S. 
producers of cumene are provided in Table 5-4. 11,78 


.5-26 





TABLE 5-4. U.S. PRODUCERS OF CUMENE 


Plant 

Location 

Annual 
Capacity 
million lb 
(million kg) 

Notes 

Ashland Chemical Company 

Catlettsburg, KY 

550 (249) 

Cumene is sold 

BTL Specialty Resins Corporation 

Blue Island, IL 

120 (54) 

Captive for phenol and 
acetone 

Chevron Chemical Company 

Philadelphia, PA 

450 (204) 

Cumene is sold 


Port Arthur, TX 

450 (204) 

Cumene is sold 

Citgo Petroleum Corp. 

(Champlin) 

Corpus Christi, TX 

825 (374) 

— 

Coastal Refining 

Westville, NJ 

150 (68) 

Cumene is sold 

Georgia Gulf Corporation 

Pasadena, TX 

1,420 (644) 

Some cumene transferred to 
company's phenol/acetone 

plant 

Koch Refining Company 

Corpus Christi, TX 

750 (340) 

Cumene is sold 

Shell Chemical Company 

Deer Park, TX 

900(408) 

Captive for phenol/acetone 

Texaco Chemical Company 

El Dorado, KS 

135 (61) 

Captive for phenol/acetone 


Source: References 11 and 78. 

Note: This list is subject to change as market conditions change, facility ownership changes, plants are closed, 

etc. The reader should verify the existence of particular facilities by consulting current list and/or the 
plants themselves. The level of benzene emissions from any given facility is a function of variables 
such as capacity, throughput, and control measures, and should be determined through direct contacts 
with plant personnel. These locations, producers, and capacities were current as of November 1993. 


5.3.1 Process Descriptions for Cumene Production bv Alkylating Benzene with 

Propylene 

Cumene is present in crude oils and refinery streams. However, all commercial 
cumene is produced by the reaction of benzene and propylene. 


Benzene and propylene are reacted at elevated temperatures and pressures in the 
presence of an acidic catalyst. A simplified equation for this reaction is as follows: 


5-27 








C 6 H 6 + CH^CHCHj [catalyst] (CH 3 ) 2 CHC 6 H 5 
(benzene) (propylene) - (cumene) 


The exothermic reaction is typically conducted using solid phosphoric acid as a 
catalyst, but the reaction may also be conducted using aluminum chloride or sulfuric acid as 
the catalyst. The aluminum chloride and sulfuric acid processes are similar; therefore, the 
sulfuric acid process is not described here. 79 

Solid Phosphoric Acid Catalyst Process 

Figure 5-7 is a typical flow diagram for the manufacture of cumene by the 
process using phosphoric acid as the catalyst support. 80 Solid phosphoric acid is the most 
favored catalyst system for manufacturing cumene and is a selective alkylation catalyst that 
promotes the alkylation of benzene with propylene in a vapor-phase system. 79 

Because the catalyst is selective, propylene feedstock for this process does not 
have to be thoroughly refined before use. Crude propylene streams (Stream 1) from refinery 
crackers that are fractionated to about 70 percent propylene can be used without further 
purification. The benzene (Stream 2) used in this process does not have to be dried before use 
because the catalyst system requires small amounts of water vapor in the reactor stream to 
activate the catalyst. 79 

Propylene and benzene (Streams 1 and 2) are combined in a feed drum and then 
fed (Stream 3) to a reactor containing the phosphoric acid catalyst. The feed ratio is normally 
at least four moles of benzene per mole of propylene. An excess of benzene is maintained in 
order to inhibit side reactions. The propylene is completely consumed. From the reactor, the 
byproducts, unreacted material, and product are separated by distillation. The reaction 
products (Stream 4) are sent to a depropanizers where residual hydrocarbons (mostly propane) 
are removed. The propane (Stream 5) is sent through a condenser, after which some of the 


5-28 


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5-29 


Figure 5-7. Process for the Manufacture of Cumene Using Solid Phosphoric Acid 

Catalyst 












































recovered propane is recycled to the reactor (Stream 6) for cooling. The remainder (Stream 7) 
can be returned to a refinery for use as feedstock or fuel gas. 79 

Unpurified product from the depropanizer (Stream 8) is sent to the benzene 
distillation column, where unreacted benzene is recovered overhead (Stream 9), sent through a 
condenser, and recycled to the feed drum (Stream 10). From the bottom of the benzene 
column (Stream 11), the crude product is sent to the cumene distillation column, where the 
high-purity cumene is separated from heavy aromatics and then condensed (Stream 12) and 
stored (Stream 13). The bottoms (compounds of relatively lower volatility) from cumene 
distillation (Stream 14) contain primarily diisopropylbenzene and are sent to a refinery or used 
as fuel gas. 79 


The cumene distillation column is normally operated slightly above atmospheric 
pressure and is padded with methane (or nitrogen) to protect the cumene from contact with the 
air. As the pressure fluctuates, a pressure-control valve relieves excess pressure on this system 
by bleeding off a mixture of methane (or nitrogen) and cumene vapor (Vent A). 79 

Aluminum Chloride Catalyst Process 

The production of cumene using an aluminum chloride catalyst is similar to that 
using a solid phosphoric acid catalyst. The aluminum chloride method requires additional 
equipment to dry recycled streams and to neutralize reaction products. Figure 5-8 shows a 
typical process diagram for cumene manufacture using aluminum chloride as the alkylation 
catalyst. Aluminum chloride is a much more active and much less selective alkylation catalyst 
than solid phosphoric acid. 79 

The aluminum chloride used as a catalyst in this process is received and handled 
as a dry powder. To prevent undesirable side reactions, the propylene used with this catalyst 
system must be of chemical grade (95 percent pure) and must contain no more than minute 
amounts of other olefins such as ethylene and butylene. This propylene feedstock must also be 


5-30 


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5-31 


Figure 5-8. Process for the Manufacture of Cumene Using Aluminum Chloride 

Catalyst 























































dried and treated (Stream 1) to remove any residual organic sulfur compounds. The benzene 
used in this process must be azeotropically dried (Stream 2) to remove dissolved water. The 
azeotrope drying distillation generates a vent gas (Vent A) that is rich in benzene. 79 

Benzene and propylene (Streams 3 and 4) are fed to a catalyst mix tank, where 
the aluminum chloride powder (Stream 5) is added. This mixture is treated with HC1 gas 
(Stream 6) to activate the catalyst. The catalyst preparation operation generates a vent gas 
consisting of inert gases and HC1 gas saturated with vapors of benzene and diisopropylbenzene. 
A scrubber is typically used to absorb the HC1 gas and the residual vapors are then vented 
(Vent B). The resulting catalyst suspension (Stream 7) and additional dried benzene (Stream 8) 
are fed to the alkylation reactor as liquids, and additional dried propylene (Stream 9) is 
introduced into the bottom of the reactor. The feed ratio to the alkylation reactor is maintained 
at or above four moles of benzene per mole of propylene to inhibit side reactions. 79 

The crude reaction mixture from the alkylation reactor (Stream 10) is sent to a 
degassing vessel, where hydrocarbons such as propane are released from solution (Stream 11). 
This vapor stream is scrubbed with a weak caustic solution and then fed (Stream 12) to the 
diisopropylbenzene (DIPB) scrubber, where the hydrocarbon vapor is recontacted with DIPB 
to extract residual unreacted propylene. The stream containing the propylene (Stream 13) is 
sent to the catalyst mix tank. 79 

The degassed product (Stream 14) is sent to the acid wash tank, where it is 
contacted with a weak acid solution that breaks down the catalyst complex and dissolves the 
aluminum chloride in the water layer. The crude product from the acid wash tank is sent to a 
decanter tank, where the water is removed. The product is then sent to a caustic wash tank, 
where any residual acid in the product is extracted and neutralized. The product is decanted 
again to remove water and then enters a water wash tank, where it is mixed with fresh process 
water. This process water extracts and removes any residual salt or other water soluble 
material from the product. The product from the water wash tank is sent to a third decanter 
tank, where the crude product and water settle and separate. 79 


.5-32 


The entire wash-decanter system is tied together by one common vent-pad line 
that furnishes nitrogen for blanketing this series of tanks. A pressure control valve on the end 
of the vent-pad manifold periodically releases vent gas (Vent C) as levels rise and fall in the 
various tanks of the wash-decanter system. The vent gas is saturated with water vapor and 
hydrocarbon vapor (principally benzene) as contained VOC. 79 

The washed and decanted product (Stream 15) is stored in a washed-product 
receiver tank. The crude product from the washed-product tank (Stream 16) is sent to a 
recovery column, where the excess benzene is stripped out. The recovered benzene 
(Stream 17) is returned to the benzene feed tank. The vent line associated with the benzene 
recovery column and with the benzene receiver tank releases some vent gas (Vent D). This 
vapor is principally inert gas saturated with benzene vapor as contained VOC. 79 

The crude cumene (Stream 18) is sent to the cumene distillation column for 
distillation of the cumene product. The cumene product (Stream 19) is then stored for sale or 
in-plant use. The cumene distillation column and the associated cumene receiver tank are 
operated above atmospheric pressure and are blanketed with nitrogen (or methane) to protect 
the cumene from reacting with oxygen in the air and forming cumene hydroperoxide. The vent 
line associated with the cumene distillation column and with the cumene receiver tank releases 
some vent gas (Vent E). This vent gas is nitrogen (or methane) saturated with cumene vapor 
as the contained VOC. 79 

The bottoms from the cumene distillation column contain a small amount of 
cumene, along with mixed isomers of diisopropylbenzene and a small amount of higher-boiling 
alkylbenzenes and miscellaneous tars. The bottoms stream (Stream 20) is sent to a DIPB 
stripping column, where DIPB is recovered and then stored (Stream 21). This stripping 
column is normally operated under vacuum because of the high-boiling points of the DIPB 
isomers. The vacuum system on the stripping column draws a vent stream from the column 
condenser, and this vent stream is air (or inert gas) saturated with cumene and DIPB vapors as 


5-33 



the contained VOC. Depending on the design and operation of the vacuum system for the 
column, part or all of the vent gas could be discharged to the atmosphere (Vent F). 79 

The bottoms from the DIPB stripper (Stream 22) are stored in a receiver tank 
and then sent to waste disposal for use as a fuel. The recycle DIPB (Stream 23) is sent to the 
DIPB scrubber, where it is used to absorb residual propylene from the propane waste gas 
stream. This recycle DIPB eventually returns to the alkylation reactor, where it is 
transalkylated with excess benzene to generate additional cumene. 79 

5.3.2 Benzene Emissions From Cumene Production 

Information related to benzene emissions from process vents, equipment leaks, 
storage vessels, wastewater collection and treatment systems, and product loading and 
transport operations associated with cumene production is presented below. Where a literature 
review has revealed no source-specific emission factors for uncontrolled or controlled benzene 
emissions from these emission points, the reader is referred to Section 5.10 of this chapter, 
which provides a general discussion of methods for estimating uncontrolled and controlled 
benzene emissions from these emission points. 

Benzene Emissions from the Solid Phosphoric Acid Catalyst Process 

In the solid phosphoric acid process, potential process vent emissions of benzene 

may be associated with the cumene column vent (Vent A in Figure 5-7). Using methane to 
pressurize the system, the process operates at a pressure slightly higher than atmospheric 
pressure to make sure that no air contacts the product. 80 The methane is eventually vented to 
the atmosphere, carrying with it other hydrocarbon vapors. 80 

No specific emission factors were found for benzene emissions from the cumene 
column. One factor for total VOC emissions indicated that 0.015 lb (0.03 kg) of total VOC 
are emitted per ton (Mg) of cumene produced, and that benzene constituted a “trace amount” 


5-34 



of the hydrocarbons in the stream. 80 One cumene producer has indicated that it uses a closed 
system (all process vents are served by a plant flare system). Thus, it is possible that there are 
no process vent emissions occurring directly from the production of cumene, although there 
may be emissions from the flares. 79 

Benzene Emissions from the Aluminum Chloride Catalyst Process 

Process vent emissions of benzene from the production of cumene using an 
aluminum chloride catalyst are associated with the benzene drying column (Vent A in 
Figure 5-8), the scrubber or the catalyst mix tank (Vent B), the wash-decanter system 
(Vent C), the benzene recovery column (Vent D), the cumene distillation system (Vent E), and 
the DIPB stripping system (Vent F). 80 No specific emission factors were located for benzene 
emissions from these sources. However, as presented in Table 5-5, one reference provided 
total VOC emission factors and estimates of benzene percent composition of the emissions. 3,80 
The percent (weight) of benzene may be used along with a cumene production volume to 
calculate an estimate of benzene emissions from these sources. The control technique most 
applicable to these sources is flaring, with an estimated efficiency of at least 98 percent (see 
Section 4.5.1 of this chapter for further discussion of this control device). 

5.4 PHENOL PRODUCTION 

Most U.S. phenol (97 percent) is produced by the peroxidation of cumene, a 
process in which cumene hydroperoxide (CHP) is cleaved to yield acetone and phenol, as well 
as recoverable by-products a-methylstyrene (AMS) and acetophenone. Phenol is also 
produced by toluene oxidation and distillation from petroleum operations. 81,82 Table 5-6 shows 
the locations, capabilities, and production methods of the phenol producers in the United 
States. 11,81,83 Because benzene may be present in the feedstock, it may be emitted during 
production of phenol. 


5-35 


TABLE 5-5. SUMMARY OF EMISSION FACTORS FOR CUMENE PRODUCTION 
AT ONI FACILITY USING THE ALUMINUM CHLORIDE CATALYST 


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5-36 













TABLE 5-6. U.S PRODUCERS OF PHENOL 



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Stimson Lumber Company Anacortes, WA <5(<2.3) Petroleum 

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5-38 











In the process involving peroxidation of cumene, acetone and phenol are 
produced by the peroxidation of cumene followed by cleavage of the resulting CHP. The two 
basic reactions for this process are as follows: 80 

C 6 H 5 CH(CH 3 ) 2 + 0 2 - C 6 H 5 COOH (CH 3 ) 2 

(cumene) (air) (cumene hydroperoxide) 

[H.SOJ 

C 6 H 5 COOH(CH 3 ) 2 ^ CH 3 COCH 3 + C 6 H 5 OH 
(cumene hydroperoxide) (acetone) (phenol) 

5.4.1 Phenol Production Techniques 

There are two technologies for producing phenol by the peroxidation of 
cumene-one licensed by Allied Chemical and the other licensed by Hercules. The major 
. differences between the Allied and Hercules processes involve the operating conditions of the 
peroxidation reaction and the method of neutralization of the acid in the cleavage product. 
These differences affect plant design primarily in the peroxidation and cleavage-product 
neutralization steps, in the location of process emission points, and in the potential quantity of 
process emissions. These two process types are discussed below. 80 

In addition to the two cumene peroxidation processes, phenol is produced by the 
oxidation of toluene. This process is described below; however, the description is brief 
because of limited available information on the process. 

Allied Process 

Figure 5-9 shows a typical flow diagram for the manufacture of phenol by the 
Allied process. 79 Cumene (Stream 1), manufactured on site or shipped to the site, and recycle 
cumene (Stream 2) are combined (Stream 3) and fed with air (Stream 4) to the multiple-reactor 
system, where cumene is oxidized to form CHP. Substantial quantities of cumene (Stream 5) 
are carried out of the reactors with the spent air to a refrigerated vent system, where part of the 


5-39 






5-40 


Figure 5-9. Flow Diagram for Phenol Production from Cumene Using the Allied Process 
















































































































cumene is recovered and recycled. 80 Uncondensed vapors, including organic compounds, are 
vented (Vent A). 

The reaction product (Stream 6), containing primarily cumene and CHP, is 
vacuum flashed first in the pre-flash distillation column and then (Stream 8) in the flash 
distillation column to remove most of the cumene, which is recycled (Streams 7 and 9). 
Uncondensed vapors, including organic compounds, are vented (Vents B and C). The 
concentrated CHP (Stream 10) flows through the CHP concentrate tank to the cleavage reactor, 
where the CHP is cleaved to acetone and phenol by the addition of S0 2 (Stream 11). The 
cleavage product (Stream 12) is neutralized in ion-exchange columns and fed through the 
crude-product surge tank (Stream 13) to a multi-column distillation system. 80,84,85 

In the primary crude acetone distillation column, acetone and lower-boiling 
impurities such as acetaldehyde and formaldehyde are distilled overhead. This product 
(Stream 14) is condensed and flows through the crude acetone surge tank to the acetone 
refining column, where the acetone is distilled overhead. Acetone product is condensed 
(Stream 15) and sent to storage. Uncondensed vapors, including organic compounds, are 
vented from the condensers after both the primary crude acetone and acetone refining columns 
(Vents D and E). 80,84 

The compounds of relatively lower volatility (bottoms) from the primary crude 
acetone column (Stream 16) are distilled in the cumene recover}' column to remove residual 

cumene. The overheads from the cumene recovery column are sent through a condenser 
(Stream 17) and into a secondary crude acetone distillation column to further remove acetone 
from the residual cumene. The residual cumene (i.e., the bottoms from the secondary crude 
acetone column) is stored for recycling. 80 The uncondensed vapors from the condensers, 
following both the cumene recovery column and secondary crude acetone column are vented 
(Vents F and G). The condensed overheads from the secondary crude acetone column 
(Stream 18) are fed through a crude acetone surge tank back to the acetone refining column. 


5-41 


Some facilities using this process may not incorporate the secondary crude 
acetone distillation column, which is utilized both to further recover acetone product and to 
reduce organic emissions from the storage tanks containing the recycle cumene. Some 
processes store the condensed product from the overhead of the cumene recovery column as 
the recycle cumene (Stream 17). 

The bottoms from the cumene recovery column (Stream 19) contain primarily 
phenol, AMS, acetophenone, and other organics with higher boiling points than phenol. This 
stream is fed to the crude AMS distillation column. The crude AMS distillation column 
overhead stream (Stream 20) is condensed and sent to the AMS refining column. Uncondensed 
vapors from the condenser after the crude AMS distillation column are vented (Vent H). The 
stream entering the AMS refining column undergoes distillation to refme out AMS. The 
refined overhead stream is condensed (Stream 21) and sent to additional columns (not shown) 
for further refining. 

The uncondensed vapors from the condenser following the AMS refining 
column are vented (Vent I). The bottoms from the AMS refining column (Stream 22) are 
stored in a crude phenol tank. The phenol in this storage tank is either sold as crude product 
or is fed to the phenol refining column for further refining. Crude phenol from the bottom of 
the crude AMS column (Stream 23) flows to the phenol refining column, where phenol is 
distilled overhead, condensed, (Stream 24), and fed to phenol product storage tanks. The 
uncondensed vapors from the condenser following the phenol refining column are vented 
(Vent J). 80 - 84 - 85 


The bottoms from the phenol refining column (Stream 25) are further processed 
to recover phenol. The bottoms are sent to a phenol topping column, from which the overhead 
stream is condensed (Stream 26) and fed to phenol product storage. Uncondensed vapors from 
the condenser after the phenol topping column are vented (Vent K). The bottoms from the 
phenol topping column (Stream 27) are fed to a phenol residue stripping column, which 
removes phenol residue in the bottoms (Stream 29). The phenol residue may be used as fuel 


5-42 


for on-site industrial boilers. The overheads from the phenol residue stripping column are 
condensed (Stream 28) and fed back to the phenol topping column to further recover phenol 
product. The uncondensed vapors from the condenser following the phenol residue stripping 
column are vented (Vent L). 84,85 

The phenolic wastewater generated by the Allied process (e.g., generated by 
recovery devices, such as condensers and scrubbers) is fed through distillation columns to 
further recover acetone and phenol products. This batch distillation cycle, which is not a 
continuous process, is not shown in Figure 5-9. Phenolic wastewater is fed through a 
dephenolizer (i.e., a steam stripping process) and one or two batch distillation columns. The 
recovered product is crude phenol or acetol phenol. 84 ' 86 

Hercules Process 

Figure 5-10 shows a typical flow diagram for the manufacture of acetone and 
phenol by the Hercules process. 79 Cumene from storage (Stream 1) and recycle cumene 
(Streams 2 and 9) are combined (Stream 3) and then fed with air (Stream 4) to the multiple- 
reactor system. Additionally, an aqueous sodium carbonate solution (Stream 5) is fed to the 
reactor system to promote the peroxidation reaction. In the reactor system, cumene is 
peroxidized to cumene hydroperoxide. Unreacted cumene is carried out of the reactors with 
the spent air (Stream 6) to a refrigerated vent system, where part of the cumene is recovered 
and recycled (Stream 2). Uncondensed vapors are vented (Vent A). 80 

The oxidation reaction product (Stream 7) flows into a separator to remove 
spent carbonate solution and then is washed with water to remove remaining carbonate and 
other soluble components. The air stream removed is sent to a condenser from which 
uncondensed vapors are vented (Vent B). The washed product (Stream 8) is fed to a 
distillation column operated under vacuum, where the cumene hydroperoxide is separated from 
the cumene. The overheads from the CHP concentrator are condensed and the recovered 


5-43 


cf-cf 


(1-4) 4i»-^-MT4-EW0H 



5-44 


Figure 5-10. Flow Diagram for Phenol Production Using the Hercules Process 














































































It-*) 41V-«t-M'l;ft>Q0»« 



5-45 









































































cumene (Stream 9) is recycled. The uncondensed vapors from the condenser are vented 
(Vent C). 


The concentrated CHP (Stream 10) is transferred through a surge tank to the 
cleavage reactor (Stream 11). Sulfuric acid, diluted to 5 to 10 percent with acetone 
(Stream 12), is added to catalyze the decomposition of CHP to acetone and phenol. 80 
Uncondensed vapors captured from the cleavage reactor are vented (Vent D). Excess acid in 
the cleaved mixture (Stream 13) is neutralized with sodium hydroxide solution (Stream 14). 
The neutralized product (Stream 15) flows through the crude-product surge tank to a 
multi-column distillation train to produce product-grade acetone, phenol, and AMS. 80 

The crude product is separated in the first distillation column into a crude 
acetone fraction (Stream 16) and a crude phenol stream (Stream 17). The crude acetone 
(Stream 16) is combined with recycled hydrocarbons from the phenol topping column 
(Stream 18) and fed through a surge tank to the light-ends column (Stream 19) to strip 
low-boiling hydrocarbon impurities, such as acetaldehyde and formaldehyde, which are vented 
to the atmosphere (Vent E). 

The bottoms stream from the light-ends column (Stream 20) is fed to the acetone 
finishing column, where the acetone is distilled overhead, condensed (Stream 21), and sent to 
day tanks and subsequently to acetone product storage and loading. Uncondensed vapors are 
vented (Vent F). The bottoms stream (Stream 22) is processed to produce AMS (not shown). 80 

The crude phenol stream (Stream 17) and the bottoms from the phenol finishing 
column (Stream 23) are fed to the heavy-ends column and distilled under vacuum to separate 
tars (Stream 24) from the impure phenol stream (Stream 25). 80 Uncondensed vapors from the 
condenser following the heavy-ends column are vented (Vent G). 

The impure phenol is fed to the phenol topping column to remove hydrocarbons 
such as cumene and AMS. The overhead stream from the phenol topping column (Stream 18) 


5-46 


may be condensed and recycled to the light-ends column of the acetone process for removal of 
residual acetone, cumene, and AMS. The uncondensed vapors from the condenser following 
the phenol topping column are vented (Vent H). The phenolic stream (Stream 26) is then fed 

to a dehydrating column, where water is removed overhead as a phenol/water azeotrope. 

* 

Uncondensed vapors are vented (Vent I). 80 

The dried phenol stream (Stream 27) is distilled under vacuum in the phenol 
finishing column to separate product-quality phenol (Stream 28) from higher boiling 
components (Stream 23), which are recycled to the heavy ends column. Uncondensed vapors 
from the condenser after the phenol finishing column are vented (Vent J). The product-quality 
phenol is stored in tanks for subsequent loading. 80 

Toluene Oxidation Process 

In this process, toluene is oxidized by air to benzoic acid. Following 
separation, the benzoic acid is catalytically converted to phenol. 

5.4.2 Benzene Emissions from Phenol Production 

Information related to benzene emissions from process vents, equipment leaks, 
storage vessels, wastewater collection and treatment systems, and product loading and 
transport operations associated with phenol production is presented below. Where a literature 
review revealed no source-specific emission factors for uncontrolled or controlled benzene 
emissions from these emission points, the reader is referred to Section 5.10 of this chapter, 
which provides a general discussion of methods for estimating uncontrolled and controlled 
benzene emissions from these types of emission points. 

“Spent air” from the oxidizer reactor (Vent A, Figure 5-9) is the largest source 
of benzene emissions at phenol production plants utilizing the Allied process. 87 Table 5-7 
provides uncontrolled and controlled (i.e., thermal oxidizer) emission factors from the oxidizer 


5-47 



TABLE 5-7. SUMMARY OF EMISSION FACTORS FOR PHENOL PRODUCTION 

BY THE PEROXIDATION OF CUMENE 


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5-48 










reactor vent from the phenol production process based on the peroxidation of cumene. 88,89 
Charcoal adsorption is the most commonly used method to control emissions from the oxidizer 
reactor vent; however, condensation, absorption, and thermal oxidation have also been used. 90 
Recovery devices (i.e., one or more condensers and/or absorbers) are the most commonly used 
methods to recover product and control emissions from the cleavage (Vent D, Figure 5-9) and 
product purification distillation columns; however, adsorption and incineration have also been 
used for emissions reduction. 81,90 

5.5 NITROBENZENE PRODUCTION 

Benzene is a major feedstock in commercial processes used to produce 
nitrobenzene. Approximately 5 percent of benzene production in the United States is used in 
the production of nitrobenzene. 12 In these processes, benzene is directly nitrated with a 
mixture of nitric acid, sulfuric acid, and water. 

As of February 1991, five companies were producing nitrobenzene in the United 
States. 91 Their names and plant locations are shown in Table 5-8. 11 In addition to these plants, 
plans are underway for Miles and First Chemical to start up a possible 250-million-pound 
(113.4-Gg) aniline plant, along with feedstock nitrobenzene, at Baytown, Texas. 92 

A discussion of the nitrobenzene production process, potential sources of 
benzene emissions, and control techniques is presented in this section. Unless otherwise 
referenced, the information that follows has been taken directly from Reference 93. 

5.5.1 Process Descriptions for Continuous Nitration 

Nitrobenzene is produced by a highly exothermic reaction in which benzene is 
reacted with nitric acid in the presence of sulfuric acid. Most commercial plants use a continuous 


5-49 



TABLE 5-8. PRODUCERS OF NITROBENZENE 


Company 

Location 

Capacity in 
million Ib/yr 
(million kg/yr) 

Rubicon, Inc. 

Geismar, LA 

550 (250) 

First Chemical Corporation 

Pascagoula, MS 

536 (244) 

E.I. duPont de Nemours and 
Company, Inc. 

Beaumont, TX 

350 (160) 

BASF Corporation 
(Polymers Division 

Urethanes) 

Geisman, LA 

250(110) 

Miles, Inc. (Polymers 

Division Polyurethane) 

New Martinsville, WV 

100 (45) 

TOTAL 


1,786 (809) 


Source: Reference 11. 

Note: This list is subject to change as market conditions change, facility ownership changes, plants are closed, etc. 

The reader should verify the existence of particular facilities by consulting current lists and/or the plants 
themselves. The level of benzene emissions from any given facility is a function of variables such as 
capacity, throughput, and control measures, and should be determined through direct contacts with plant 
personnel. These data on producers and location were current as of January 1993. 

nitration process, where benzene and the acids are mixed in a series of continuous stirred- 
tank reactors. 94 A flow diagram of the basic continuous process is shown in Figure 5-11, 93 

As shown in the figure, nitric acid (Stream 1) and sulfuric acid (Stream 2) are mixed before 
flowing into the reactor. Benzene extract (Stream 6), two recovered and recycled benzene 
streams (Streams 7 and 8), and as much additional benzene (Stream 9) as is required are combined 
to make up the benzene charge to the reactor. 

For the process depicted here, nitration occurs at 131 °F (55°C) under 
atmospheric pressure. Cooling coils are used to remove the heat generated by the reaction. 


5-50 







M1J6S00»6 



5-51 


Figure 5-11. Process Flow Diagram for Manufacture of Nitrobenzene 










































































Following nitration, the crude reaction mixture (Stream 3) flows to the decanter, 
where the organic phase of crude nitrobenzene is separated from the aqueous waste acid. The 
crude nitrobenzene (Stream 12) subsequently flows to the washer and neutralizer, where 
mineral (inorganic) and organic acids are removed. The washer and neutralizer effluent are 
discharged to wastewater treatment. The organic layer (Stream 13) is fed to the nitrobenzene 
stripper, where water and most of the benzene and other low-boiling-point components are 
carried overhead. The organic phase carried overhead is primarily benzene and is recycled 
(Stream 7) to the reactor. The aqueous phase (carried overhead) is sent to the washer. 

Stripped nitrobenzene (Stream 14) is cooled and then transferred to nitrobenzene storage. 

The treatment, recycling, or discharge of process streams is also shown in the 
flow diagram. Aqueous waste acid (Stream 4) from the decanter flows to the extractor, where 
it is denitrated. There, the acid is treated with fresh benzene from storage (Stream 5) to 
extract most of the dissolved nitrobenzene and nitric acid. The benzene extract (Stream 6) 
flow's back to the nitrating reactor, whereas the denitrated acid is stored in the waste acid tank. 

Benzene is commonly recovered from the waste acid by distillation in the acid 
stripper. The benzene recovered is recycled (Stream 8), and water carried overhead with the 
benzene is forwarded (Stream 11) to the washer. The stripped acid (Stream 10) is usually 
reconcentrated on site but may be sold. 93 

Typically, many of the process steps are padded with nitrogen gas to reduce the 
chances of fire or explosion. This nitrogen padding gas and other inert gases are purged from 
vents associated with the reactor and separator (Vent A in Figure 5-11), the condenser on the 
acid stripper (Vent B), the washer and neutralizer (Vent C), and the condenser on the 
nitrobenzene stripper (Vent D). 


5-52 


5.5.2 


Benzene Emissions from Nitrobenzene Production 


Benzene emissions may occur at numerous points during the manufacture of 
nitrobenzene. These emissions may be divided into four types: process emissions, storage 
emissions, equipment leak emissions, and secondary emissions. 

Process emissions occur at the following four gas-purge vents: the reactor and 
separator vent (A), the acid stripper vent (B), the washer and neutralizer vent (C), and the 
nitrobenzene stripper vent (D). The bulk of benzene emissions occur from the reactor and 
separator vent. This vent releases about three times the level of benzene released from 
Vents B and D (Figure 5-11), and about 120 times that released from Vent C. For all of these 
vents, the majority of VOC emissions is in the form of benzene. Benzene accounts for 99, 

100, 76, and 99 percent of total VOC emissions from Vents A, B, C, and D, respectively. 
Table 5-9 shows estimated emission factors for benzene from these sources. 93 

Other emissions include storage, equipment leak, and secondary emissions. 
Storage emissions (G) occur from tanks storing benzene, waste acid, and nitrobenzene. 
Equipment leak emissions of benzene can occur when leaks develop in valves, pump seals, and 
other equipment. Leaks can also occur from corrosion by the sulfuric and nitric acids and can 
hinder control of fugitive emissions. 

Secondary emissions can result from the handling and disposal of process waste 
liquid. Three potential sources of secondary benzene emissions (J) are the wastewater from the 
nitrobenzene washer, waste caustic from the nitrobenzene neutralizer, and waste acid from the 
acid stripper. Where waste acid is not stripped before its sale or reconcentration, secondary 
emissions will be significantly affected (increased) unless the reconcentration process is 
adequately controlled. 

Table 5-9 gives benzene emission factors before and after the application of 
possible controls for two hypothetical plants using the continuous nitration process. The two 


5-53 



TABLE 5-9. SUMMARY OF EMISSION FACTORS FOR HYPOTHETICAL NITROBENZENE 

PRODUCTION PLANTS 


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5-55 


For 331 million Ib/vr (150.000 Me/vr) Model Plant 
Tank Si/e ft 3 (m 3 ) Tumovers/Year Bulk Liquid Temperature °F (°G 

Benzene (large tank) 160,035 (4,730) 24 68 (20) 

Benzene (small tank) 16,704 (473) 236 68 (20) 















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plants differ in capacity; one produces 198 million lb/yr (90,000 Mg/yr) and the other 
331 million lb/yr (150,000 Mg/yr) of nitrobenzene. Both plants use a vent absorber or thermal 
oxidizer to control process emissions in conjunction with waste-acid storage and small benzene 
storage emissions. 

The values presented for the main benzene storage emissions were calculated by 
assuming that a contact-type internal floating roof with secondary seals will reduce fixed-roof 
tank emissions by 85 percent. The values presented for controlled equipment leak emissions 
are based on the assumption that leaks from valves and pumps, resulting in concentrations 
greater than 10,000 ppm on a volume basis, are detected, and that appropriate measures are 
taken to correct the leaks. 

Secondary emissions and nitrobenzene storage emissions are assumed to be 
uncontrolled. Uncontrolled emission factors are based on the assumptions given in the 
footnotes to Table 5-9. The total controlled emission factors for these hypothetical plants 
range from 0.44 to 0.78 lb/ton (0.22 to 0.39 kg/Mg). Actual emissions from nitrobenzene 
plants would be expected to vary, depending on process variations, operating conditions, and 
control methods. 93 

A variety of control devices may be used to reduce emissions during 
nitrobenzene production, but insufficient information is available to determine which devices 
nitrobenzene producers are using currently. Process emissions may be reduced by 
vent absorbers, water scrubbers, condensers, incinerators, and/or thermal oxidizers. 

Storage emissions from the waste-acid storage tank and the small benzene 
storage tank can be readily controlled in conjunction with the process emissions. (A small 
storage tank contains approximately one day's supply of benzene; the larger tank is the main 
benzene storage tank.) In contrast, emissions from the main benzene storage tanks are 
controlled by using floating-roof storage tanks. 


5-57 





Equipment leak emissions are generally controlled by leak detection and repair, 
whereas secondary emissions are generally uncontrolled. 

5.6 ANILINE PRODUCTION 

Almost 97 percent of the nitrobenzene produced in the United States is 
converted to aniline. 91 Because of its presence as an impurity in nitrobenzene, benzene may be 
emitted during aniline production. Therefore, a brief discussion of the production of aniline 
from nitrobenzene and its associated benzene emissions is included in this document. 

Table 5-10 lists the U.S. producers of aniline and the production method. 11 The 
mam derivative of aniline (75 percent) is p.p.-methylene diphenyl diisocyanate (MDI). The 
growth outlook for aniline is expected to remain strong because of its continued use in housing 
and automobile parts. 95 

5.6.1 Process Descriptions for Aniline Production for Nitrobenzene 

A process flow diagram of the most widely used process for manufacturing of 
aniline—by hydrogen reduction of nitrobenzene-is shown in Figure 5-12. 96 As shown in the 
figure, nitrobenzene (Stream 1) is vaporized and fed with excess hydrogen (Stream 2) to a 
fluidized-bed reactor. The product gases (Stream 3) are passed through a condenser. The 
condensed materials are decanted (Stream 4), and non-condensible materials are recycled to the 
reactor (Stream 5). In the decanter, one phase (Stream 6) is crude aniline and the other is an 
aqueous phase (Stream 7). 

The crude aniline phase is routed to a dehydration column that operates under 
vacuum. Aniline is recovered from the aqueous phase by stripping or extraction with 
nitrobenzene. Overheads from the dehydration column (Stream 8) are condensed and recycled 
to the decanter. The bottoms from the dehydration column (Stream 9), which contain aniline, 


5-58 





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»n producers and locations were current as of January 1, 1993. 







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are sent to the purification column. Overheads (Stream 10) from the purification column 
contain the aniline product, while the bottoms (Stream 11) contain tars. 

Fourteen percent of current aniline production (produced by Miles, Inc.) 
involves an acid-iron reduction process where iron oxide is created as a co-product. 
Nitrobenzene is reacted with iron and dilute hydrochloric acid at reflux. When the reaction is 
complete, the aniline-water mixture is separated from the iron-hydroxide sludge and the 
heavier aniline layer is removed and vacuum distilled to yield purified aniline. 18 

5.6.2 Benzene Emissions from Aniline Production 

Process emissions of benzene typically originate from the purging of non¬ 
condensibles during recycle to the reactor and purging of inert gases from separation and 
purification equipment (Vent A in Figure 5-12). 9 

Only one emission factor was found for benzene emissions from aniline 
production. For process vents (Vent A), an uncontrolled emission factor of 0.0114 lb 
benzene/ton aniline produced (0.0057 kg/Mg) was reported in the literature. 96 The SCC code 
for this emission point is 3-01-034-03: Aniline-Reactor Recycle Process Vent. No details of 
the emission factor derivation were provided, other than it was based on data provided by an 
aniline producer, so it was assigned a U rating. 

Control techniques available for emissions associated with the purging of 
equipment vents include water scrubbing and thermal oxidation. 96 No data were found to 
indicate the efficiencies of these control devices for benzene emissions. The reader is urged to 
contact specific production facilities before applying the emission factor given in this report to 
determine exact process conditions and control techniques. 


5-61 




5.7 


CHLOROBENZENE PRODUCTION 


The most important chlorobenzenes for industrial applications are 
monochlorobenzene (MCB), dichlorobenzene (DCB), and trichlorobenzene (TCB). Therefore, 
this section focuses on benzene emissions associated with production of these three types of 
chlorobenzenes. Table 5-11 lists the U.S. producers of MCB, DCB, and TCB. The producing 
companies' capabilities are flexible, such that different chlorobenzenes may be isolated, 
depending on market demand. DCBs and TCBs are produced in connection with MCB. The 
relative amounts of the products can be varied by process control. 97 

5.7.1 Process Desc ription for Chlorobenze ne Production bv Direct Chlorination of 

Benzene 


The most widely used process for the manufacture of chlorobenzenes is direct 
chlorination of benzene in the presence of ferric chloride catalyst to produce MCB and DCB. 
HC1 is a by-product. The two major isomers of DCB are ortho and para. As chlorination 
continues, tri-, tetra-, penta-, and, finally, hexachlorobenzenes are formed. However, TCB is 
the only one of the more highly chlorinated products found in significant amounts. 

Basic operations that may be used in the continuous production of MCB are 
shown in Figure 5-13. 19 The process begins with a series of small, externally cooled cast iron 
or steel vessels containing the catalyst (which may consist of Rashing rings of iron or iron 
wire). Chlorine is supplied into each vessel through suitably positioned inlets to maintain a 
large benzene-to-chlorine reaction at all points along the reaction stream. The temperature is 
held between 68 to 104°F (20 to 40°C) to minimize the production of DCBs, which form at 
higher temperatures. Dry benzene (Stream 1) and dried recycled benzene (Stream 2) are 
introduced into the reactor, which produces an overhead gas (Stream 3). 

The gas stream (containing HC1, unreacted chlorine, inert gases from the 
chlorine feed, benzene, and other VOC) is sent to an organic absorber, where benzene and 


5-62 





TABLE 5-11. U.S. PRODUCERS OF MONO-, DI-, AND TRICHLOROBENZENE 


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ownership changes, or plants are closed down. The reader should verify the existence of particular facilities by consulting current lists or the 
plants themselves. The level of emissions from any given facility is a function of variables such as throughput and control measures, and should 
be determined through direct contacts with plant personnel. The data on producers and locations were current as of January 1993. 






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5-64 


Figure 5-13. Monochlorobenzene Continuous Production Process Diagram 








































































































other VOC are removed. The bottoms from the organic absorber (Stream 6) flow to the HC1 
stripper for recovery of HC1. The overhead gas (Stream 5) is sent to HC1 absorption. 
By-product HC1 is then removed in the HC1 absorber, where it is saturated by washing with a 
refrigerated solvent (e.g., o-DCB) or low vapor pressure oil, and then recovered in wash 
towers as commercially usable hydrochloric acid. 98 

Crude reaction liquid product (Stream 4) enters the crude chlorobenzene 
distillation column, which produces overheads (Stream 7) that contains most of the 
chlorobenzenes, unreacted benzene, and some HC1, and a bottom stream from which catalyst 
and other byproducts are separated (Stream 8) and processed for reuse. The overheads 
(Stream 7) pass through an HC1 stripper and into a benzene recovery column (Stream 9). Part 
of the subsequent benzene-free stream (Stream 10) is returned to the organic absorber; the 
remainder (Stream 11) enters the MCB distillation column. The overhead MCB distillation 
product (Stream 12) is then stored and the bottom stream containing DCB and TCB isomers is 
processed. 98 


Figure 5-14 presents basic operations that may be used to produce o- and p-DCB 
and TCB. In a continuation of the production of MCB, o- and p-DCB can be separated by 
fractional distillation. Isomer fractionation yields p-DCB (with traces of o-DCB and m-DCB), 
which enters the overhead (Stream 1); the o-DCB enters the bottoms (Stream 2). The o-DCB 
bottoms (Stream 2) undergoes fractional distillation and produces an o-DCB overhead 
(Stream 3), which is sent to storage, and bottoms (Stream 4), which is further processed to 
yield TCBs. 98 


The crude p-DCB with other trace isomers (Stream 5) is purified by batch 
crystallization. Part of the purified p-DCB (Stream 6) is sent to liquid storage. The remainder 
(Stream 7) undergoes freezing, crushing, screening, and packing of p-DCB crystals. The 
mother liquor from crystallization (Stream 8) is sent to DCB solvent-grade ffactionalization, 
where it is separated into solvent grade o-DCB (Stream 9) and p-DCB (Stream 10) and 
stored. 98 


5-65 



0\ 


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5-66 


Figure 5-14. Dichlorobenzene and Trichlorobenzene Continuous Production Diagram 

















































































The isolation of m-DCB from mixed DCB streams is not economical, because it 
usually occurs at a level of 1 percent or less. Metadichlorobenzene is sold with other isomers 
as mixed chlorobenzenes. 98 

* 

Other processes that are most often used in the production of MCB are the batch 
and Rashing methods. 98 Other TCB production processes are the reaction of a, P, or 
y-benzene hexachloride with alcoholic potash, the dehalogenation of a-benzene hexachloride 
with pyridine, and the reaction of a-benzene hexachloride with calcium hydroxide to form 
primarily 1,2,4-TCB. 19 

5.7.2 Benzene Emissions from Chlorobenzene Production 

The primary source of benzene emissions during MCB production is the tail gas 
treatment vent of the tail gas scrubber (Vent A in Figure 5-13). Usually, this vent does not 
have a control device. 19 Other potential sources of benzene emissions are atmospheric 
distillation vents from the benzene drying column, heavy-ends processing, the benzene 
recovery column, and MCB distillation (Vents B, C, D, E in Figure 5-13, respectively), 
equipment leak emissions, emissions from benzene storage, and secondary emissions from 
wastewater. 19 

Table 5-12 presents estimated controlled and uncontrolled emission factors for 
benzene emissions from the tail gas treatment vent, atmospheric distillation vents, equipment 
leak emissions, and benzene storage. 19 The point source factors are based on emissions 
reported to EPA in response to information requests and trip reports. 19 For information on 
emission factors for estimating equipment leak and storage tank emissions refer to 
Sections 4.5.2 and 4.5.3 respectively of this document. As noted in Table 5-12, carbon 
adsorption is an appropriate control technology for control of emissions from tail gas treatment 
and distillation column vents. The control technique applicable to process equipment leak 
emissions is an inspection/maintenance program for pumps, valves, and flanges. Internal 
floating roof tanks may be used to control benzene emissions resulting from benzene storage. 19 


5-67 



TABLE 5-12. EMISSION FACTORS FOR CHLOROBENZENE PRODUCTION BY DIRECT 

CHLORINATION OF BENZENE 


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5-68 











TABLE 5-12. CONTINUED 


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5-69 





I 


5.8 LINEAR ALKYLBENZENE PRODUCTION 

Approximately 2 percent of the benzene produced in the United States is used in 
the production of linear alkylbenzene (LAB). LAB (or linear alkylate) improves the surfactant 
performance of detergents. The primary end use for LAB is in the production of linear 
alkylbenzene sulfonates (LAS). Because of their water-soluble properties, LAS are used 
extensively in powdered home laundry products (over 50 percent of LAS produced) and in 
heavy-duty liquid products." 

Alkyl benzene sulfonates with highly branched C 12 side chains possess excellent 
detergent properties, and they have also been used in the past in formulating detergents. 
However, in recent years, LAS have essentially replaced all branched alkylbenzene sulfonates 
in detergent formulations in the United States because of environmental considerations. LAB 
is extensively degraded (> 90 percent) by microorganisms in sewage plants after a relatively 
short period of time. In comparison, the highly branched alkyl benzene sulfonates have a 
much lower biological degradability. 100 Dodecylbenzene and tridecylbenzene are the two most 
common LABs. The locations of the LAB producers in the United States are shown in 
Table 5-13. 1U01 


In the United States, LAB is produced using two different processes. Vista's 
Baltimore plant uses a monochloroparaffin LAB production process. Vista's Lake Charles 
plant and Monsanto's Alvin plant use an olefin process, wherein hydrogen fluoride serves as a 
catalyst. Approximately 64 percent of LAB is produced by the olefm process. The paraffin 
chlorination process accounts for about 36 percent of LAB production. Both processes are 
described in the following sections. 

5.8.1 Process Description for Production of LAB Using the Olefin Process 

Production of LAB using the olefin process consists of two steps: a 
dehydrogenation reaction and an alkylation reaction. The C 10 to C 14 linear paraffins are 


5-70 




TABLE 5-13. U.S. PRODUCERS OF LINEAR ALKYLBENZENE (DETERGENT ALKYLATES) 


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5-71 


changes, or plants are closed down. The reader should verify the existence of particular facilities by consulting current listings or the plants 
themselves. The level of emissions from any given facility is a function of variables, such as throughput and control measures, and should be 
determined through direct contacts with plant personnel. These data for producers and locations were current as of January 1993. 











dehydrogenated to n-olefins, which are reacted with benzene under the influence of a solid, 
heterogenous catalyst (such as hydrogen fluoride [HF1]) to form LAB. The discussion of LAB 
production using the olefm process is taken from references 102 and 103. 

First, n-paraffms are transferred from bulk storage to the linear paraffin feed 
tank in Stream 1 (Figure 5-15.) 103 The paraffins are heated to the point of vaporization 
(Stream 2) and passed through a catalyst bed in the Pacol reactor (Stream 3), where the feed is 
dehydrogenated to form the corresponding linear olefins by the following reaction: 

R, - CH 2 - CH 2 - R 2 —> Rj CH = CH - R 2 + H 2 

The resulting olefins contain from 10 to 30 percent a-olefms, and a mixture of internal olefms, 
unreacted paraffins, some diolefins, and lower-molecular-weight “cracked materials.” The gas 
mixture is quickly quenched with a cold liquid stream as it exits to process thermally-promoted 
side reactions (Stream 4). The hydrogen-rich offgases (e.g., hydrogen, methane, ethane, etc.) 
are then separated from the olefin liquid phases (Stream 5). The gas is used as process fuel 
(Stream 6) or vented to a flare stack. 

Di-olefins in the Pacol separator liquid are selectively converted back to 
mono-olefins in the Define reactor (Stream 7). The effluent from the reactor is routed to a 
stripper (Stream 8), where light ends are removed (Stream 9). The olefin-paraffin mixture 
(Stream 10) is then alkylated with benzene (Stream 11) in the fixed-bed reactor to be blended 
with a HF1 catalyst. The blend is held at reaction conditions long enough for the alkylation 
reaction to go to completion as follows: 

R,CH = CHR 2 + C 6 H 6 — > R t CH 2 - CHR 2 

Product from the reactor flows to the benzene stripping column (Stream 12) for separation and 
recycle of unreacted benzene to the fixed-bed reactor (Stream 13). The liquid HF1 is also 
separated and recycled to the alkylation vessel to be mixed with fresh HF1. 


5-72 


Fraah Banzana 


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5-73 


Figure 5-15. Linear Alkybenzene Production Using the Olefin Process 





















































































Following benzene stripping, a lime water solution is then fed into the HF1 
scrubber column (Stream 14) to neutralize the HF1. The solution is filtered (Stream 15); the 
wastewater is routed to the treatment facility and the solids are transferred to a landfill. 
Unreacted paraffins are separated in the paraffin stripping column (Stream 16) and recycled to 
the Pacol reactor (Stream 17). The last distillation column purifies the main LAB (Stream 18). 
Heavy alkylate byproducts are stored (Stream 19) and the pure LAB is transferred to storage 
tanks (Stream 20) awaiting sale. 

5.8.2 Benzene Emissions from LAB Produ ction Using the Olefin Process 

Benzene emissions from the LAB olefin process are shown in Table 5-14. 102 
The two major sources of emissions are the benzene azeotropic column (Vent A) and the HF1 
scrubber column controlling emissions from the benzene stripping column (Vent B). Some 
benzene can be emitted through the HF1 scrubber column. Inert gases and air venting from the 
unit, temperature, and purge rate of the scrubber can influence the amount of volatiles emitted. 
These gases are usually sent to a flare. The control for both of these emissions is use as fuel. 
Benzene emissions can also occur from benzene storage tanks and equipment leaks. Refer to 
Section 4.5 for a discussion of benzene emissions from these sources. 

5.8.3 Process Description for Production of LAB Using the Chlorination Process 

The LAB chlorination process consists of two sequential reactions. In the first 
step, n-paraffins are chlorinated to monochlorinated n-paraffins. In the second reaction, 
benzene and crude secondary alkyl chlorides (chloroparaffins) are blended with an aluminum 
chloride catalyst to form crude LAB. The following discussion of LAB production using the 
chlorination process is taken from references 100 and 102. 

As shown in Figure 5-16, n-paraffins (alkanes) (Stream 1) are reacted with 
liquid chlorine (Stream 2) in a series of UV-catalyzed chlorination reactors. 100 The n-paraffins 


5-74 






TABLE 5-14. SUMMARY OF EMISSION FACTORS FOR HYPOTHETICAL LINEAR ALKYLBENZENE PLANT 

USING THE OLEFIN PROCESS 


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5-75 






Alkylbenzene 

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5-76 


Figure 5-16. Production of Linear Alkybenzenes via Chlorination 





































































are converted at 212°F (100°C) to a mixture of about 35 percent chlorinated paraffins, and the 
remainder to paraffins and HC1 as shown in the following reaction:. 


Ri - CH 2 - R 2 + Cl —> R - CH - R 2 + HC1 + heat 

Cl 

Following this reaction, dehydrochlorination (elimination of HC1) of the monochloroalkanes 
takes place at 392 to 752 °F (200 to 300°C) over an iron catalyst to form olefins (linear alkenes 
with internal double bonds) (Stream 3). It is necessary to remove all chlorinated paraffins 
(such as dichloroalkenes) from the process stream because they form other products besides 
LAB. Therefore, the remaining chlorinated paraffins are dehydrochlorinated to give tar-like 
products that are easily separated and recycled back to the reactor (Stream 4). HC1 is also 
removed from the mixture (Stream 5), leaving a mixture of only olefins and paraffins for the 
alkylation reaction. 100 

This olefin-paraffin mixture (Stream 6) is combined with benzene from storage 
that has been dried in a benzene azeotropic column (Stream 7). These two streams are 
combined in an alkylation reactor with an aluminum chloride catalyst at 122 °F (50 °C) 

(Stream 8). The subsequent reaction produces LAB, illustrated below: 

Rj - CH - R ; + C 6 H 6 —> Rj - CH - R 2 + HC1 + heat, possible olefins, 

short-chained paraffins, etc. 

Cl 


At this point, HC1 gas and some fugitive volatile organics given off during the 
reaction are treated with adsorbers and excess HC1 is routed to storage (Vent B). Next, the 
LAB (Stream 9) is routed to a separator where hydrolysis is performed in the presence of HF1 
at 50°F (10°C) to separate crude LAB and the organics (benzene, tar, etc.) (Stream 10) from 
the catalyst sludge (Stream 11). Benzene is recovered in the benzene stripping column and 
recycled back to the reactor (Stream 12). 


5-77 


The resulting paraffin-alkylate mixture (Stream 13) is sent through rectification 
and purification (which includes washing and decanting) to yield pure alkylbenzene and 
paraffin, which can be recycled as feedstock. 100 

5.8.4 Benzene Emissions from LAB Production Using the Chlorination Process 

Benzene emissions using the LAB chlorination process are shown in Table 5-14. 
The four major points of benzene emissions are listed below. Emission factors for these points 
also are presented in Table 5-15. 102 

One emission point is the benzene azeotropic column vent, which serves to dry 
the benzene before it enters the alkylation reactor. Some benzene emissions can escape from 
the vent in the column (Vent A). The quantity of escaping emissions is dependent on the 
dryness of the benzene and the design of the column condenser. 

A second emission point is the hydrochloric acid adsorber vent. Following the 
alkylation reaction, the HC1 gas and fugitive volatile organics are treated by absorbers. Most 
of the product goes to hydrochloric acid storage, but some is vented off (Vent B). The amount 
of benzene emissions given off here is dependent on the fluid temperature in the absorber and 
the vapor pressure of the mixed absorber fluid. 

The third type of emission point is the atmospheric wash decanter vents. In the 
final purification/rectification stage, the crude LAB is washed with alkaline water to neutralize 
it. Benzene emissions can escape from these atmospheric washer vents (Vent C). 

Finally, in the benzene stripping column, benzene is recovered and returned to 
the benzene feed tank. Residual inert gases and benzene emissions can occur at this point 
(Vent D). The amount of benzene in the stream depends on the quantity of inert gases and the 
temperature and design of the reflux condenser used. 


5-78 




TABLE 5-15. SUMMARY OF EMISSION FACTORS FOR HYPOTHETICAL LINEAR ALKYLBENZENE'PLANT 

USING THE CHLORINATION PROCESS 


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contact plant personnel to confirm the existence of emitting operations and control technology at a particular facility prior to estimating emissions 
therefrom. 
















The most frequently applied control option for all of these sources is to use the 
emissions for fuel. 

5.9 OTHER ORGANIC CHEMICAL PRODUCTION 

Several additional organic chemicals that are produced using benzene as a 
feedstock are believed to have benzene emissions. These chemicals include hydroquinone, 
benzophenone, benzene sulfonic acid, resorcinol, biphenyl, and anthraquinone. 68 A brief 
summary of the producers, end uses, and manufacturing processes for these chemicals is given 
below. No emissions data were available for these processes. 

5.9.1 Hvdroquinone 

The primary end use of hydroquinone is in developing black-and-white 
photographic film (46 percent). A secondary end use is as a raw material for rubber 
antioxidants (31 percent). 104 

A technical grade of hydroquinone is manufactured using benzene and propylene 
as raw materials by Goodyear Tire and Rubber Company in Bayport, TX,11 million lb/yr 
(5 million kg/yr) and by the Eastman Chemical Company, Tennessee Eastman Division, in 
Kingsport, Tennessee, 26 million lb/yr (12 million kg/yr). 11,101 

In this process, benzene and recycled cumene are alkylated with propylene in 
the liquid phase over a fixed-bed silica-alumina catalyst to form a mixture of 
diisopropylbenzene isomers. The meta isomer is transalkylated with benzene over a fixed bed 
silica-alumina catalyst to produce cumene for recycle. The para isomer is hydroperoxidized in 
the liquid phase, using gaseous oxygen, to a mixture of diisopropylbenzene hydroperoxide 
isomers. The mono isomer is recycled to the hydroperoxidation reactor. The 
diisopropylbenzene hydroperoxide is cleaved in the liquid phase with sulfuric acid to 
hydroquinone and acetone. Acetone is produced as a co-product. 104 


5-80 



5.9.2 


Benzophenone 


Benzophenone (diphenylketone) is used as an intermediate in organic synthesis, 
and as an odor fixative. Derivatives are used as ultraviolet (UV) absorbers, such as in the UV 
curing of inks and coatings. 105 Benzophenone is also used as flavoring, soap fragrance, in 
pharmaceuticals, and as a polymerization inhibitor for styrene. Nickstadt-Moeller, Inc., in 
Ridgefield, New Jersey, and PMC, Inc., PMC Specialties Group Division in Chicago, Illinois, 
produce a technical grade of benzophenone. 11 Benzophenone is also produced by Upjohn 
Company, Fine Chemicals. 101 Benzophenone is produced by acylation of benzene and benzyl 
chloride. 68 

5.9.3 Benzene Sulfonic Acid 


Benzene sulfonic acid is used as a catalyst for furan and phenolic resins and as a 
chemical intermediate in various organic syntheses including the manufacture of phenol and 
resorcinol. 105,106 Benzene sulfonic acid is manufactured by sulfonation—reacting benzene with 
fuming sulfuric acid. 106 Burroughs Wellcome in Greenville, North Carolina; CL Industries, 
Inc., in Georgetown, Illinois; and Sloss Industries Corporation in Birmingham, Alabama, 
produce benzene sulfonic acid. 11 

5.9.4 Resorcinol 


Resorcinol is produced by INDSPEC Chemical Corporation in Petrolia, 
Pennsylvania. 11 Resorcinol is produced by fusing benzene-m-disulfonic acid with sodium 
hydroxide. Resorcinol is used in manufacturing resorcinol-formaldehyde resins, dyes, and 
pharmaceuticals. It is also used as a cross-linking agent for neoprene, as a rubber tackifier, in 
adhesives for wood veneers and runner-to-textiles composites, and in the manufacture of 
styphnic acid and cosmetics. 106 


5-81 





5.9.5 


Biphenvl 


Biphenyl (diphenyl or phenylbenzene) is produced by Chemol Co. in 
Greensboro, North Carolina; Koch Refining Co. in Corpus Christi, Texas; Monsanto Co. in 
Anniston, Alabama; Sybron Chemical Inc., in Wellford, South Carolina; and Chevron 
Chemical Co. of Chevron Corp. 11,101 One method for producing biphenyl is by 
dehydrogenation-slowly passing benzene through a red-hot iron tube. 106 

Biphenyl is used in organic synthesis, as a heat-transfer agent, as a fungistat in 
packaging citrus fruit, in plant disease control, in the manufacture of benzidine, and as a 
dyeing assistant for polyesters. 106 In 1991, 8,976 tons (8,143 Mg) of biphenyl were sold. 101 

5.9.6 Anthraquinone 

Anthraquinone is manufactured by heating phthalic anhydride and benzene in the 
presence of aluminum chloride and dehydrating the product. Anthraquinone is used as an 
intermediate for dyes and organics, as an organic inhibitor, and as a bird repellent for seeds. 

5.10 BENZENE USE AS A SOLVENT 

Benzene has been used historically as an industrial solvent. Because benzene is 
readily soluble in a variety of chemicals (including alcohol, ether, and acetone), it has 
commonly been used as an agent to dissolve other substances. As an industrial solvent, 
benzene application has included use as an azeotropic agent, distilling agent, reaction solvent, 
extracting solvent, and recrystallizing agent. However, benzene use as an industrial solvent 
has been steadily declining over the last few years because of its adverse health effects and 
increased regulation. The Occupational Safety and Health Administration has cited health risk 
to workers from exposure to benzene, and EPA has classified benzene as a Group A chemical, 
a known human carcinogen. 107 


5-82 




Source categories that currently use benzene as a solvent include pharmaceutical 
manufacturing; general organic synthesis; alcohol manufacturing; caprolactam production, and 
plastics, resins, and synthetic rubber manufacturing. Benzene is also used in small quantities 
(generally less than 0.1 percent) in solvents used in the rubber tire manufacturing industry; 
however, the amount of emissions generated is variable depending on the amount of solvent 
used. 108 

Facilities in the above-listed source categories indicate that they plan to 
eliminate benzene solvent use in the next few years. 107 Facilities have been experimenting with 
substimtes, such as toluene, cyclohexane, and monochlorobenzene. However, those facilities 
that continue to use benzene indicate that they have been unable to identify a solvent substitute 

as effective as benzene. 109 

Several facilities in the source categories listed above reported benzene 
emissions in the 1992 TRI. These facilities and their locations are included in Table 5-16. 

Emissions of benzene from solvent used in the manufacture and use of 
pesticides, use of printing inks, application of surface coatings, and manufacture of paints are 
believed to be on the decline or discontinued. 107110 However, several facilities in these source 
categories reported benzene emissions in the 1992 TRI. 111 These facilities and their locations 
are also included in Table 5-16. 11 * 

Benzene continues to be used in alcohol manufacture as a denaturant for ethyl 
alcohol. It is also used as an azeotropic agent for dehydration of 95 percent ethanol and 
91 percent isoproponal. 109 Companies currently producing these alcohols are presented in 
Table 5-17. lun 

Benzene is also used as a solvent to extract crude caprolactam. 112 The three 
major caprolactam facilities currently operating in the United States are listed in 


5-83 



TABLE 5-16. PARTIAL LIST OF MANUFACTURERS IN SOURCE CATEGORIES 

WHERE BENZENE IS USED AS A SOLVENT 


Solvent Use Source Category 

Location 

Plastics Materials and Resins 

* 

Amoco Chemical Co. 

Arizona Chemical Co. 

Chemfax Inc. 

Exxon Chemical Americas Baton 

Rouge Resin Finishing 

Formosa Plastics Corp. 

Lawter Inti. Inc. 

Southern Resin Division 

Neville Chemical Co. 

Quantum Chemical Corp. La Porte 

Quantum Chemical Corp. 

USI Division 

Rexene Corp. Polypropylene Plant 

Union Carbide Chemicals & Plastics 

Co. Texas City Plant 

Moundville, AL 

Gulfport, MS 

Gulfport, MS 

Baton Rouge, LA 

Point Comfort, TX 

Moundville, AL 

Pittsburgh, PA 

La Porte, TX 

Clinton, LA 

Odessa, TX 

Texas City, TX 


Pharmaceutical Manufacturing 


Warner-Lambert Co. 

Parke Davis Division 

Holland, MI 

Pesticides and Agricultural Chemicals 


Rhone-Poulenc Ag Co. 

Agribusiness Maketers, Inc. 

Institute, WV 

Baton Rouge, LA 

Commercial Printing (Gravure) 


Piedmont Converting, Inc. 

Lexington T NC 


(continued) 


5-84 





TABLE 5-16. CONTINUED 


’ ^ 


Solvent Use Source Category 

Location 

♦Paints and Allied Products 

- 

BASF Corporation Inks & Coating 
v Division 

St. Louis Paint Manufacturing Co., 

Inc. 

Greenville, OH 

St. Louis, MS 


Synthetic Rubber 


DuPont Pontchartrain Works 

La Place, LA 

DuPont Beaumont Plant 

Beaumont, TX 


Source: Reference 111 


5-85 





TABLE 5-17. U.S. PRODUCERS OF ETHANOL OR ISOPROPANOL 


Facility 

Location 

Annual Capacity 
million gal 
(million L) 

anol 

• 


Archer Daniels Midland Company 

Cedar Rapids, IA 

700 (2,650) 

ADM Com Processing Division 

Clinton, LA 



Decatur, IL 

Peoria, IL 

Walhalla, ND 

11 (42) 

Biocom USA Ltd. 

Jennings, LA 

40 (151) 

Cargill, Incorporated 

Eddyville, IA 

30(113) 

Domestic Com Milling Division 

Chief Ethanol Fuels Inc. 

Hastings, NB 

14 (53) 

Eastman Chemical Company 

Longview, TX 

25 (95) 

Texas Eastman Division 

Georgia-Pacific Corporation 

Bellingham, WA 

12 (45) 

Chemical Division 

Giant Refining Co. 

Portales, NM 

10 (38) 

Grain Processing Corporation 

Muscatine, IA 

60 (227) 

High Plains Corp. 

Colwich, KS 

15 (57) 

Hubinger-Roquette Americas, Inc. 

Keokuk, IA 

11 (42) 

Midwest Grain Products, Inc. 

Atchison, KS 

22 (83) 


Pekin, IL 

19 (72) 

Minnesota Com Processors 

Columbus. NB 

NA 


Marshall, MN 

28 (106) 

New Energy Company of Indiana 

South Bend, IN 

70 (265) 

Pekin Energy Company 

Pekin, IL 

80 (303) 

Quantum Chemical Corp. 

Tuscola, IL 

68 (257) 

USI Division 

South Point Ethanol 

South Point, OH 

60 (227) 

A. E. Staley Manufacturing Company 

Loudon, TN 

60 (227) 


Sweetner Business Group 
Ethanol Division 


(continued) 


5-86 






TABLE 5-17. CONTINUED 


Facility 

Location 

Annual Capacity 
million gal 
(million L) 

Ethanol (continued) 

• 


Union Carbide Corporation 

Solvents and Coatings Materials Division 

Texas City, TX 

123 (466) 


TOTAL 

1,458 (5,519) 

Isopropanol 



Exxon Chemical Company 

Exxon Chemical Americas 

Baton Rouge, LA 

650 (2,460) 

Lyondell Petrochemical Company 

Shell Chemical Company 

Channel view, TX 

Deer Park, TX 

65 (246) 

600 (2,271) 

Union Carbide Corporation 

Solvents and Coatings Materials Division 

Texas City, TX 

530 (2,006) 


TOTAL 

1,845 (6,984) 


Source: References 11 and 111. 

J Emissions listed are those reported in the 1992 TRI. 
NA = Not available 

= no emissions reported 


5-87 





Table 5-18. 11,111 Of the three facilities, DSM and BASF use benzene as a solvent, and Allied Signal 
produces benzene as a co-product. 113 

Benzene is also used as a solvent in the blending and shipping of aluminum alkyls. 113 

Emission points identified for solvent benzene are process vents, dryer vents, and 
building ventilation systems. 107 As shown in Table 5-19, only one emission factor was identified for 
any of the solvent use categories. 114 The emission factor presented is for the vacuum dryer vent 
controlled with a venturi scrubber in pharmaceutical manufacturing. 


5-88 


TABLE 5-18. U.S. PRODUCERS OF CAPROLACTAM 


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SECTION 6.0 

EMISSIONS FROM OTHER SOURCES 


The following activities and manufacturing processes (other than benzene 
production or use of benzene as a feedstock) were identified as additional sources of benzene 
emissions: oil and gas wellheads, petroleum refineries, glycol dehydrators, gasoline 
marketing, publicly owned treatment works (POTWs), landfills, pulp and paper 
manufacturing, synthetic graphite manufacturing, carbon black manufacturing, rayon-based 
carbon manufacturing, aluminum casting, asphalt roofing manufacturing, and use of consumer 
products and building supplies. 

For each of these categories, the following information is provided in the 
sections below: (1) a description of the activity or process, (2) a brief characterization of the 
national activity in the United States, (3) benzene emissions characteristics, and (4) control 
technologies and techniques for reducing benzene emissions. In some cases, the current 
Federal regulations applicable to the source category are discussed. 

6.1 OIL AND GAS WELLHEADS 

6.1.1 Description of Oil and Gas Wellheads 

Oil and gas production (through wellheads) delivers a stream of oil and gas 
mixture and leads to equipment leak emissions. Emissions from the oil and gas wellheads. 


6-1 





including benzene, are primarily the result of equipment leaks from various components at the 
wellheads (valves, flanges, connections, and open-ended lines). Component configurations for 
wellheads can vary significantly. 

Oil and gas well population data are tracked by State and Federal agencies, 
private oil and gas consulting firms, and oil and gas trade associations. In 1989 a total of 
262,483 gas wells and 310,046 oil wells were reported in the United States. 115,116 
Reference 117 presents a comprehensive review of information sources for oil and gas well 
count data. The activity factor data are presented at four levels of resolution: (1) number of 
wells by county, (2) number of wells by State, (3) number of fields by county, and (4) number 
of fields by State. 

6.1.2 Benzene Emissions from Oil and Gas Wellheads 

Emissions from oil and gas wellheads can be estimated using the average 
emission factor approach as indicated in the EPA Protocol for Equipment Leak Emission 
Estimates. 54 This approach allows the use of average emission factors in combination with 
wellheads-specific data. These data include: (1) number of each type of components (valves, 
flanges, etc.), (2) the service type of each component (gas, condensate, mixture, etc.), (3) the 
benzene concentration of the stream, and (4) the number of wells. 

A main source of data for equipment leak hydrocarbon emission factors for oil 
and gas field operations is an API study 118 developed in 1980. 

Average gas wellhead component count has been reported as consisting of 
11 valves, 50 screwed connections, 1 flange, and 2 open-ended lines. 119 No information was 
found concerning average component counts for oil wellheads. 

Benzene and total hydrocarbons equipment leak emission factors from oil 
wellheads are presented in Table 6-1. 120 These emission factors were developed from 


6-2 



TABLE 6-1. BENZENE AND TOTAL HYDROCARBONS EQUIPMENT LEAK EMISSION FACTORS 

FOR OIL WELLHEAD ASSEMBLIES" 


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Field wellhead only. Does not include other field equipment (such as dehydrators, separators, inline heaters, treaters, etc. 









screening and bagging data obtained in oil production facilities located in California. 120 Over 
450 accessible production wellhead assemblies were screened, and a total of 28 wellhead 
assemblies were selected for bagging. For information about screening and bagging 
procedures refer to Reference 54. 

The composition of gas streams varies among production sites. Therefore, 
when developing benzene emission estimates, the total hydrocarbons emission factors should 
be modified by specific benzene weight percent, if available. 

Benzene constituted from less than 0.1 up to 2.3 percent weight of total 
non-methane hydrocarbons (TNMHC) for water flood wellhead samples from old crude oil 
production sites in Oklahoma. Also, benzene constituted approximately 0.1 percent weight of 
TNMHC for gas driven wellhead samples. 121 The VOC composition in the gas stream from 
old production sites is different than that from a new field. Also, the gas-to-oil ratio for old 
production sites may be relatively low. 121 The above type of situations should be analyzed 
before using available emission factors. 

6.2 GLYCOL DEHYDRATION UNITS 

Glycol dehydrators used in the petroleum and natural gas industries have only 
recently been discovered to be an important source of volatile organic compound (VOC) 
emissions, including benzene, toluene, ethylbenzene, and xylene (BTEX). Natural gas is 
typically dehydrated in glycol dehydration units. The removal of water from natural gas may 
take place in field production, treatment facilities, and in gas processing plants. Glycol 
dehydration units in field production service have smaller gas throughputs compared with units 
in gas processing service. It has been estimated that between 30,000 and 40,000 glycol 
dehydrating units are in operation in the United States. 122 In a survey conducted by the 
Louisiana Department of Environmental Quality, triethylene glycol (TEG) dehydration units 
accounted for approximately 95 percent of the total in the United States, with ethylene glycol 
(EG) and diethylene glycol (DEG) dehydration units accounting for approximately 5 percent. 123 


6-4 







Data on the population and characteristics of glycol dehydration units 
nationwide is limited. Demographic data has been collected by Louisiana Department of 
Environmental Quality, Texas Mid-Continent Oil and Gas Association and Gas Processors 
Association, Air Quality Service of the Oklahoma Department of Health (assisted by the 
Oklahoma Mid-Continent Oil and Gas Association), and Air Quality Division of the Wyoming 
Department of Environmental Quality. 124 Table 6-2 presents population data and 
characteristics of glycol dehydration units currently available. 124 

6.2.1 Process Description for Glvcol Dehydration Units 

The two basic unit operations occurring in a glycol dehydration unit are 
absorption and distillation. Figure 6-1 presents a general flow diagram for a glycol 
dehydration unit. 125 The “wet” natural gas (Stream 1) enters the glycol dehydrator through an 
inlet separator that removes produced water and liquid hydrocarbons. The gas flows into the 
bottom of an absorber (Stream 2), where it comes in contact with the “lean” glycol (usually 
triethylene glycol [TEG]). The water and some hydrocarbons in the gas are absorbed by the 
glycol. The “dry” gas passes overhead from the absorber through a gas/glycol exchanger 
(Stream 3), where it cools the incoming lean glycol. The gas may enter a knock-out drum 
(Stream 4), where any residual glycol is removed. From there, the dry natural gas goes 
downstream for further processing or enters the pipeline. 

After absorbing water from the gas in the absorber, the “rich” glycol (Stream 5) 
is preheated, usually in the still, and the pressure of the glycol is dropped before it enters a 
three-phase separator (Stream 6). The reduction in pressure produces a flash gas stream from 
the three-phase separator. Upon exiting the separator (Stream 7), the glycol is filtered to 
remove panicles. This particular configuration of preheat, flash, and filter steps may vary 
from unit to unit. The rich glycol (Stream 8) then passes through a glycol/glycol exchanger 
for further preheating before it enters the reboiler still. 


6-5 



TABLE 6-2. GLYCOL DEHYDRATION UNIT POPULATION DATA 


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Then, the rich glycol enters the reboiler still (Stream 9) (operating at 
atmospheric pressure), where the water and hydrocarbons are distilled (stripped) from the 
glycol making it lean. The lean glycol is pumped back to absorber pressure and sent to the 
gas/glycol exchanger (Stream 10) before entering the absorber to complete the loop. 

6.2.2 Benzene Emissions from Glvcol Dehydration Units 

The primary source of VOC emissions, including BTEX, from glycol 
dehydration units is the reboiler still vent stack (Vent A). 

Because the boiling points of BTEX range from 176°F to 284°F (80 to 140°C), 
they are not lost to any large extent in the flash tank but are separated from the glycol in the 
still. These separations in the still result in VOC emissions that contain significant quantities 
of BTEX. 126 


Secondary sources of emissions from glycol dehydration units are the phase 
separator vent (Vent B) and the reboiler burner exhaust stack (Vent C). 

Most glycol units have a phase separator between the absorber and the still to 
remove dissolved gases from the warm rich glycol and reduce VOC emissions from the still. 
The gas produced from the phase separator can provide the fuel and/or stripping gas required 
for the reboiler. 

A large number of small glycol dehydration units use a gas-fired burner as the 
heat source for the reboiler. The emissions from the burner exhaust stack are considered 
minimal and are typical of natural gas combustion sources. 

Reboiler still vent data have been collected by the Louisiana Department of 
Environmental Quality, 123 and the Ventura County (California) Air Pollution Control 
District. 127 Table 6-3 presents emission factors for both triethylene glycol (TEG) units and 


6-8 



TABLE 6 - 3 . REACTIVE ORGANIC COMPOUNDS (ROCs) 1 AND BTEX EMISSION FACTORS FOR 

GLYCOL DEHYDRATION UNITS 


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MMsemd = Million standard cubic meter per day. 





ethylene glycol (EG) units based on the natural gas throughput of the gas treated. The 
emission factors developed from the LDEQ study were based on responses from 41 companies 
and 208 glycol dehydration units. The Ventura County, California, factors include testing 
results at two locations (one for TEG and one for EG). The amount of produced gas treated is 
thought to be the most important because it largely determines the size of the glycol system. 127 
However, the data base does not show a strong correlation because other variables with 
countervailing influences were not constant. 127 VOC and BTEX emissions from glycol units 
vary depending upon the inlet feed composition (gas composition and water content) as well as 
the configuration, size, and operating conditions of the glycol unit (i.e., glycol type, pump 
type and circulation rate, gas and contactor temperatures, reboiler fire-cycles, and inlet 
scrubber flash tank efficiencies). 129 

The speciation of Total BTEX for TEG units reported by the LDEQ in their 
study indicated the following composition (% weight): benzene (35); toluene (36); 
ethylbenzene (5); and xylene (24). For EG units, the following compositions were reported: 
benzene (48); toluene (30); ethylbenzene (4); and xylene (17). Note that the BTEX 
composition of natural gas may vary according to geographic areas. Limited information/data 
on the BTEX composition is available. 

Four methods for estimating emissions have been reported for glycol 
dehydration units: (1) rich/lean glycol mass balance, (2) inlet/outlet gas mass balance, 

(3) unconventional stack measurements (total-capture condensation, and partial stack 
condensation/flow measurement), and (4) direct stack measurements (conventional stack 
measurements, and novel stack composition/flow measurement). 129 

Sampling of the rich/lean glycol then estimating emissions using mass balance 
has been the selected method for measuring emissions to date. The Louisiana Department of 
Environmental Quality requested emission estimates using reboiler mass balances on the 
rich/lean glycol samples. 


6-10 










Based upon a set of studies conducted by Oryx Energy Co as part of a task force 
for the Oklahoma-Kansas Midcontinent Oil & Gas Association, rich/lean glycol mass balance 
is a highly convenient, cost effective method for estimating air emissions from glycol 
dehydration units. 129 The following conclusions were addressed in reference 129 regarding this 
method: (a) good estimates of BTEX can be obtained from rich/lean glycol mass balance, 

(b) the rich/lean glycol mass balance BTEX estimates are in excellent agreement with total 
capture condensation method, and (c) rich/lean glycol mass balance is a more reproducible 
method for emission estimations than nonconventional stack methods. Note that conventional 
stack methods cannot be used on the stacks of glycol dehydration units because they are too 
narrow in diameter and have low flow rates. 

An industry working group consisting of representatives from the American 
Petroleum Institute, Gas Processors Association, Texas-Midcontinent Oil & Gas Association, 
Louisiana Mid-Continent Oil and Gas Association, and GRI is conducting field evaluation 
experiments to determine appropriate and accurate sampling and analytical methods to calculate 
glycol dehydration unit emissions. 125 GRI has developed a computer tool, entitled 
GRI-GLYCalc, for estimating emissions from glycol dehydrators. The U.S. EPA has 
performed their own field study of GRI-GLYCalc and has recommended that it be included in 
EPA guidance for State/local agency use for development of emission inventories. 130 

Atmospheric rich/lean glycol sampling is being evaluated as a screening 
technique in the above working group program. The goal is to compare these results to the 
stack and other rich/lean results and determine if a correction factor can be applied to this 
approach. 125 


A second screening technique under study is natural gas sampling and analysis 
combined with the software program GRI-GLYCalc® to predict emissions. Table 6-4 shows 
the inputs required of the user and also shows the outputs returned by GRI-GLYCalc®. 132 


6-11 


TABLE 6-4. GLYCOL DEHYDRATION EMISSION PROGRAM 

INPUTS AND OUTPUTS 


Inputs 

Units 

Gas Flow Rate 

MMscfd 

Gas Composition 

Volume percent for C r C 6 hydrocarbons and 
BTEX compounds 

Gas Pressure 

psig 

Gas Temperature 

°F 

Dry Gas Water Content 2 

lbs/MMscf 

Number of Equilibrium Stages 2 

Dimensionless 

Lean Glycol Circulation 

gpm 

Lean Glycol Composition 

Weight % H 2 0 

Flash Temperature c 

°F 

Flash Pressure c 

psig 

Gas-Driven Pump Volume Ratio c 

acffn gas/gpm glycol 

Outputs 

Units 

BTEX Mass Emissions 

lbs/hr or lb-moles/hr, lbs/day, tpy, vol% 

Other VOC Emissions 

lbs/hr or lb-moles/hr, lbs/day, tpy, vol% 

Flash Gas Composition 

Dry Gas Water Content 15 

Number of Equilibrium Stages' 5 

lbs/hr or lb-moles/hr, lbs/day, tpy, vol% 

lbs/MMscf 

Dimensionless 


Source: Reference 132. 

* Specify ong of these inputs. 

b Dry Gas Water Content is an output if the Number of Equilibrium Stages is specified and vice versa. 
c Optional 


6-12 










6.2.3 


Controls and Regulatory Analysis 


Controls applicable to glycol dehydrator reboiler still vents include hydrocarbon 
skimmers, condensation, flaring, and incineration. Hydrocarbon skimmers use a three-phase 
separator to recover gas and hydrocarbons from the liquid glycol prior to its injection into the 
reboiler. Condensation recovers hydrocarbons from the still vent emissions, whereas flaring 
and incineration destroy the hydrocarbons present in the still vent emissions. 

For glycol dehydrators it has been determined by the Air Quality Service, 
Oklahoma State Department of Health that the Best Available Control Technology (BACT) 
could include one or more of the following: (1) substitution of glycol, (2) definition of specific 
operational parameters, such as the glycol circulation rate, reduction of contactor tower 
temperature, or increasing temperature in the three-phase separator, (3) flaring/incineration, 

(4) product/vapor recovery, (5) pressurized tanks, (6) carbon adsorption, or (7) change of 
desiccant system. 128 

The Air Quality Division, Wyoming Department of Environmental Quality has 
stated that facilities will more than likely be required to control emissions from glycol 
dehydration units. The Division has determined and will accept the use of condensers in 
conjunction with a vapor recovery system, incinerator, or a flare as representing BACT. 133 

Most gas processors have begun to modify existing glycol reboiler equipment to 
reduce or eliminate VOC emissions. Some strategies and experiences from one natural gas 
company are presented in Reference 124. For other control technologies refer to 
Reference 134. 

Glycol dehydration units are subject to the NSPS for VOC emissions from 
equipment leaks for onshore natural gas processing plants promulgated in June 1985. 135 The 
NSPS provides requirements for repair schedules, recordkeeping, and reporting of equipment 
leaks. 


6-13 



The Clean Air Act Amendments (CAAA) of 1990 resulted in regulation of 
glycol dehydration units. Title III of the CAAA regulates the emissions of 188 hazardous air 
pollutants (HAPs) from major sources and area sources. Title HI has potentially wide-ranging 
effects for glycol units. The BTEX compounds are included in the list of 188 HAPs and may 
be emitted at levels that would cause many glycol units to be defined as major sources and 
subject to Maximum Achievable Control Technology (MACT). 125 

Currently, the MACT standard for the oil and natural gas production source 
category, which includes glycol dehydration units, is being developed under authority of 
Section 112(d) of the 1990 CAAA and is scheduled for promulgation in May, 1999. 

In addition to the federal regulations, many states have regulations affecting 
glycol dehydration units. The State of Louisiana has already regulated still vents on large 
glycol units, and its air toxics rule may affect many small units. Texas, Oklahoma, Wyoming, 
and California are considering regulation of BTEX and other VOC emissions from dehydration 
units. 125 

6.3 PETROLEUM REFINERY PROCESSES 

6.3.1 Description of Petroleum Refineries 

Crude oil contains small amounts of naturally occurring benzene. One estimate 
indicates that crude oil consists of 0.15 percent benzene by volume. 136 Therefore, some 
processes and operations at petroleum refineries may emit benzene independent of specific 
benzene recovery processes. Appendix B (Table B-l) lists the locations of petroleum refineries 
in the U.S. As of January 1995, there were 173 operational petroleum refineries in the United 
States, with a total crude capacity of 15.14 million barrels per calendar day. 137,138 The majority 
of refinery capacity is located in Texas, Louisiana, and California. Significant refinery 
capacities are also found in the Chicago, Philadelphia, and Puget Sound areas. A flow diagram 


6-14 




of processes likely to be found at a model refinery is shown in Figure 6-2. 139 The arrangement 
of these processes varies among refineries, and few, if any, employ all of these processes. 

Processes at petroleum refineries can be grouped into five types: (1) separation 
processes, (2) conversion processes, (3) treating processes, (4) auxiliary processes and 
operation, and (5) feedstock/product storage and handling. These are discussed briefly below. 

The first phase in petroleum refining operations is the separation of crude oil 
into its major constituents using four separation processes: (1) desalting, (2) atmospheric 
distillation, (3) vacuum distillation, and (4) light ends recovery. 

To meet the demands for high-octane gasoline, jet fuel, and diesel fuel, 
components such as residual oils, fuel oils, and light ends are converted to gasolines and other 
light fractions using one or more of the following conversion processes: (1) catalytic cracking 
(fluidized-bed and moving-bed), (2) thermal processes (coking, and visbreaking), 

(3) alkylation, (4) polymerization, (5) isomerization, and (6) reforming. 

Petroleum treating processes stabilize and upgrade petroleum products by 
separating them from less desirable products. Among the treating processes are 
(1) hydrotreating, (2) chemical sweetening, (3) deasphalting, and (4) asphalt blowing. 

Auxiliary processes and operations include process heaters, compressor engines, 
sulfur recovery units, blowdown systems, flares, cooling towers, and wastewater treatment 
facilities. 


Finally, all refineries have a feedstock/product storage area (commonly called a 
“tank farm”) with storage tanks whose capacities range from less than 1,000 barrels to more 
than 500,000 barrels. Also, feedstock/product handling operations (transfer operations) consist 
of the loading and unloading of transport vehicles (including trucks, rail cars, and marine 
vessels). 


6-15 


Fuel Oat and LPO 



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6-16 


Figure 6-2. Process Flow Diagram for a Model Petroleum Refinery 














































































































































For a -complete description of the various processes and operations at petroleum 
refineries refer to References 139, 140, and 141. 

6.3.2 Benzene Emissions from Petroleum Refinery Processes and Operations 

Benzene emissions, as well as Hazardous Air Pollutant (HAPs) emissions from 
petroleum refineries can be grouped into five main categories: (1) process vents, (2) storage 
tanks, (3) equipment leaks. (4) transfer operations, and (5) wastewater collection and 
treatment. Table 6-5 presents a list of specific processes and operations which are potential 
sources of benzene emissions at petroleum refineries emitted from one or more of the above 
categories. 139 

Also, process heaters and boilers located at the different process units across a 
refinery emit flue gases containing benzene, and other HAPs. The HAPs emitted result either 
from incomplete combustion of fuel gas or from the combustion products. 



According to the Information Collection Request (ICR) and Section 114 survey 
submitted to EPA by U.S. refiners as part of the Petroleum Refinery NESHAP study, benzene 
emissions from process vents were reported for the following process units within a refinery: 
(1) thermal cracking (coking), (2) Methyl Ethyl Ketone (MEK) dewaxing, and 
(3) miscellaneous vents at crude distillation units, catalytic reforming units, 
hydrotreating/hydrorefming, asphalt plants, vacuum distillation towers, and full-range 
distillation units (light ends, naphtha, solvent, etc.). Also, benzene emissions were reported 
from blowdown and flue gas system vents. 


The Section 114 and ICR questionnaire responses also provided estimates of 
benzene concentrations in refinery processes, and in petroleum refinery products. Table 6-6 
summarizes concentrations of benzene for gas, light liquid, and heavy liquid streams at some 
refinery process units. 142 Table 6-7 summarizes concentrations of benzene in common refinery 
products. 143,144 


6-17 








TABLE 6-5. POTENTIAL SOURCES OF BENZENE EMISSIONS AT 

PETROLEUM REFINERIES 


A Crude Storage 
B Desalting 

C Atmospheric distillation (crude unit) 

D Vacuum distillation 
E Naphtha hydrodesulfurization 
F Catalytic reforming 
G Light hydrocarbon storage and blending 
H Kerosene hydrodesulfurization 
I Gas oil hydrodesulfurization 
J Fluid bed catalytic cracking 
K Moving bed catalytic cracking 
L Catalytic hydrocracking 
M Middle distillate storage and blending 
N Lube oil hydrodesulfurization 
O Deasphalting 

P Residual oil hydrodesulfurization 
Q Visbreaking 
R Coking 

S Lube oil processing 
T Asphalt blowing 

U Heavy hydrocarbon storage and blending 
V Wastewater collection and treatment units 

Source: Reference 139. 


6-18 






TABLE 6-6. CONCENTRATION OF BENZENE IN REFINERY PROCESS UNIT 

STREAMS (WEIGHT PERCENT) 


Stream Type 

Process Unit 

Gas 

Light Liquid 

Heavy Liquid 

Crude 

1.3 

1.21 

0.67 

Alkylation (sulfuric acid) 

0.1 

0.23 

0.23 

Catalytic Reforming 

2.93 

2.87 

1.67 

Hydrocracking 

0.78 

1.09 

0.10 

Hydrotreating/hydrorefining 

1.34 

1.38 

0.37 

Catalytic Cracking 

0.39 

0.71 

0.20 

Thermal Cracking (visbreaking) 

0.77 

1.45 

1.45 

Thermal Cracking (coking) 

0.24 

0.85 

0.18 

Product Blending 

1.20 

1.43 

2.15 

Full-Range Distillation 

0.83 

1.33 

1.08 

Vacuum Distillation 

0.72 

0.15 . 

0.22 

Isomerization 

2.49 

2.49 

0.62 

Polymerization 

0.10 

0.10 

0.10 

MEK Dewaxing 

0.36 

NR 

NR 

Other Lube Oil Processing 

1.20 

1.20 

0.10 


Source: Reference 142. 
NR means not reported. 


6-19 






TABLE 6-7. CONCENTRATION OF BENZENE IN REFINERY PRODUCTS 


Material 

Weight Percent in Liquid 

Asphalt 

0.03 

Aviation Gasoline 

0.51 

Alkylale 

0.12 

Crude Oil 

0.45. 

Diesel/Distillate 

0.008 

Gasoline (all blends) 

0.90 

Heavy Gas Oil 

0.0002 

Jet Fuel 

1.05 

Jet Kerosene 

0.004 

Naphtha 

1.24 

Reformates 

4.61 

Residual Fuel Oil 

0.001 

Recovered Oil 

0.95 


Source: References 143, 144 and 158. 


6-20 







Storage tanks at petroleum refineries containing petroleum liquids are potential 
sources for benzene emissions. VOC emissions from storage tanks, including fixed-roof, 
external floating-roof, and internal floating-roof types, can be estimated using Compilation of 
Air Pollutant Emission Factors (AP-42), Chapter 7 33 and the TANKS model. Emissions of 
benzene from storage vessels may be estimated by applying the benzene concentrations in 
Table 6-7 to the equations in AP-42 which are also used in TANKS. 

Equipment leak emissions from refineries occur from process equipment 
components such as valves, pump seals, compressor seals, pressure relief valves, connectors, 
open-ended lines, and sampling connections. Non-methane VOC emissions are calculated 
using emission factors (in lb/hr/component) and emission equations developed by the EPA in 
the Protocol for Equipment Leak Emission Estimates. 54 The number of components at a 
refinery are specific to a refinery. However, model equipment counts were developed for the 
petroleum refinery NESHAP for refineries with crude charge capacities less than 
50,000 barrels/stream day (bbl/sd) and greater than or equal to 50,000 bbl/sd. These counts 
are presented in Tables 6-8 and 6-9. 142 Benzene emissions from equipment leaks may be 
estimated by multiplying the equipment counts, the equipment leak factor, and the benzene 
Concentration in the process from Table 6-6. It is generally assumed that the speciation of 
compounds inside a process line are equal to the compounds leaking. 

The Western States Petroleum Association (WSPA) and the American Petroleum 
Institute (API) commissioned the development of a 1993 refinery equipment leak study 145 to 
develop new emission factors and correlation equations. 139 The data from the 1993 study has 
been combined with data from a 1993 marketing terminal equipment leak study. 146 

For information on emission factors and equations for loading and transport 
operations, refer to Section 6.4 (Gasoline Marketing) of this document. 


6-21 




TABLE 6-8. MEDIAN COMPONENT COUNTS FOR PROCESS UNITS FROM SMALL REFINERIES 


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6-22 


Refineries with crude charge capacities less than 50,000 bbl/sd. 









TABLE 6-9. MEDIAN COMPONENT COUNTS FOR PROCESS UNITS FROM LARGE REFINERIES 


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6-23 


Refineries with crude charge capacities greater than 50.000 bbl/sd 










Air emissions from petroleum refinery wastewater collection and treatment are 
one of the largest sources of VOC emissions at a refinery and are dependent on variables 
including wastewater throughput, type of pollutants, pollutant concentrations, and the amount 
of contact wastewater has with the air. 

Table 6-10 presents model process unit characteristics for petroleum refinery 
wastewater. 147 The table includes average flow factors, average volatile HAP concentrations, 
and average benzene concentrations by process unit type to estimate uncontrolled emissions 
from petroleum refinery wastewater streams. Flow factors were derived from Section 114 
questionnaire responses compiled for the Refinery NESHAP study. Volatile HAP and 
benzene concentrations were derived from Section 114 questionnaire responses, 90-day 
Benzene Waste Operations NESHAP (BWON) reports, and equilibrium calculations. 

Uncontrolled wastewater emissions for petroleum refinery process units can be 
estimated multiplying the average flow factor, the volatile HAP concentrations, and the 
fraction emitted presented in Table 6-10, for each specific refinery process unit capacity. 

Wastewater emission factors for oil/water separators, air flotation systems, and 
sludge dewatering units are presented in Table 6-11. 148151 

Another option for estimating emissions of organic compounds from wastewater 
treatment systems is to use the air emission model presented in the EPA document Compilation 
of Air Pollutant Emission Factors (AP-42), in Section 4.3, entitled “Wastewater Collection, 
Treatment, and Storage.” 64 This emission model (referred to as SIMS in AP-42 and now 
superceded by Water 8) is based on mass transfer correlations and can predict the emissions of 
individual organic species from a wastewater treatment system. 


6-24 



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6-26 


















TABLE 6-11. WASTEWATER EMISSION FACTORS FOR PETROLEUM REFINERIES 


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6-27 


















6.3.3 


Controls and Regulatory Analysis 


This section presents information on controls for process vents at petroleum 
refineries, and identifies other sections in this document that may be consulted to obtain 
information on control technology for storage tanks, and equipment leaks. Applicable Federal 
regulations to process vents, storage tanks, equipment leaks, transfer operations, and 
wastewater emissions are briefly described. 

According to the EPA ICR and Section 114 surveys, the most reported types of 
control for catalyst regeneration process vents at fluid catalytic cracking units were 
electrostatic precipitators, carbon monoxide (CO) boilers, cyclones, and scrubbers. Some 

refineries have reported controlling their emissions with scrubbers at catalytic reformer 
regeneration vents. 

For miscellaneous process vents, including miscellaneous equipment in various 
process units throughout the refinery, the most reported controls were flares, incinerators, 
and/or boilers. Other controls for miscellaneous process vents reported by refineries include 
scrubbers, electrostatic precipitators, fabric filters, and cyclones. 

The process vent provisions included in the Petroleum Refinery NESHAP 
promulgated on September 18, 1995 affect organic HAP emissions from miscellaneous process 
vents throughout a refinery. 49 These vents include but are not limited to vent streams from 
caustic wash accumulators, distillation condensers/accumulators, flash/knock-out drums, 
reactor vessels, scrubber overheads, stripper overheads, vacuum (steam) ejectors, wash tower 
overheads, water wash accumulators, and blowdown condensers/accumulators. 

f 

For information about controls for storage tanks refer to Section 4.5.3 - Storage 
Tank Emissions, Controls, and Regulations. 

! 


6-28 









Storage tanks containing petroleum liquids and benzene are regulated by the 
following Federal rules: 


1. “National Emission Standard for Benzene Emissions from Benzene 
Vessels;” 61 



2. “Standards of Performance for Volatile Organic Liquid Storage Vessels 
(Including Petroleum Liquid Storage Vessels) for which Construction, 
Reconstruction, or Modification Commenced after July 23, 1984; ” 62 and 

3. “National Emission Standards for Hazardous Air Pollutants: Petroleum 
Refineries.” 49 


The Petroleum Refinery NESHAP requires that liquids containing greater than 


4 weight percent HAPs at existing storage vessels, and greater than 2 weight percent HAPs at 

new storage vessels be controlled. 


There are two primary control techniques for reducing equipment leak 
emissions: (1) modification or replacement of existing equipment, and (2) implementation of a 
Leak Detection and Repair (LDAR) program. 


Equipment leak emissions are regulated by the New Source Performance 
Standards (NSPS) for Equipment Leaks of VOC in Petroleum Refineries promulgated in 
May 30, 1984. 152 These standards apply to VOC emissions at affected facilities that 
commenced construction, modification, or reconstruction after January 4, 1983. 


The standards regulate compressors, valves, pumps, pressure relief devices, 
sampling connection systems, open-ended valves or lines, and flanges or other connectors in 
VOC service. 

The Benzene Equipment Leaks National Emission Standard for Hazardous Air 
Pollutants (NESHAP) 56 and the Equipment Leaks NESHAP 57 for fugitive emission sources 
regulate equipment leak emissions from pumps, compressors, pressure relief devices, sampling 
connecting systems, open-ended valves or lines, valves, flanges and other connectors, product 


6-29 








accumulator vessels, and specific control devices or systems at petroleum refineries. These 
NESHAPs were both promulgated in June 6, 1984. 

Equipment leak provisions included in the Petroleum Refinery NESHAP require 
equipment leak emissions to be controlled using the control requirements of the petroleum 
refinery equipment leaks NSPS or the hazardous organic NESHAP. 

Any process unit that has no equipment in benzene service is exempt from the 
equipment leak requirements of the benzene waste NESHAP. “In benzene service” means that 
a piece of equipment either contains or contacts a fluid (liquid or gas) that is at least 10 percent 
benzene by weight (as determined according to respective provisions). Any process unit that 
has no equipment in organic HAP service is exempt from the equipment leak requirements of 
the petroleum refinery NESHAP. “In organic HAP service” means that a piece of equipment 
contains or contacts a fluid that is at least 5 percent benzene by weight. 

Refer to Section 6.4 (Gasoline Marketing) of this L&E document for 
information on control technologies and regulations for loading and transport operations. 

For information about controls for wastewater collection and treatment systems, 
refer to Section 4.5.4 - Wastewater Collection and Treatment System Emissions, Controls, and 
Regulation. 


Petroleum refinery wastewater streams containing benzene are regulated by the 
following Federal rules: 

1. “National Emission Standard for Benzene Waste Operations;” 66 

2. “New Source Performance Standard for Volatile Organic Compound 
Emissions from Petroleum Refinery Wastewater Systems;” 153 and 

3. “National Emission Standards for Hazardous Air Pollutants: Petroleum 
Refineries.” 49 


6-30 







The wastewater provisions in the Petroleum Refinery NESHAP are the same as 
the Benzene Waste Operations NESHAP. 


6-4 GASOLINE MARKETING 








Gasoline storage and distribution activities represent potential sources of 
benzene emissions. The benzene content of gasoline ranges from less than 1 to almost 
5 percent by liquid volume, but typical liquid concentrations are currently around 0.9 percent 
by weight. 158 Under Title II of the Clean Air Act as amended in 1990, the benzene content of 
reformulated gasoline (RFG) will be limited to 1 percent volume maximum (or 0.95 percent 
volume period average) with a 1.3 percent volume absolute maximum. In California, the 
“Phase 2 Reformulated Gasoline,” which will be required starting March 1998, also has a 
1 percent volume benzene limit (or 0.8 percent volume average) with an absolute maximum of 
1.2 percent volume. 20 For this reason, it is expected that the overall average of benzene 
content in gasoline will decrease over the next few years. Total hydrocarbon emissions from 
storage tanks, material transfer, and vehicle fueling do include emissions of benzene. This 
section describes sources of benzene emissions from gasoline transportation and marketing 
operations. Because the sources of these emissions are so widespread, individual locations are 
not identified in this section. Instead, emission factors are presented, along with a general 
discussion of the sources of these emissions. 


The flow of the gasoline marketing system in the United States is presented in 
Figure 6-3. 153 The gasoline distribution network includes storage tanks, tanker ships and 
barges, tank trucks and railcars, pipelines, bulk terminals, bulk plants, and service stations. 
From refmeries, gasoline is delivered to bulk terminals by way of pipelines, tanker ships, or 
barges. Bulk terminals may also receive petroleum products from other terminals. From bulk 
terminals, petroleum products (including gasoline) are distributed by tank trucks to bulk plants. 
Both bulk terminals and bulk plants deliver gasoline to private, commercial, and retail 
customers. Daily product at a terminal averages about 250,000 gallons (950,000 liters), in 
contrast to about 5,000 gallons (19,000 liters) for an average size bulk plant. 154 


6-31 






Figure 6-3. The Gasoline Marketing Distribution System in the United States 


Source: Reference 153. 





































Service stations receive gasoline by tank truck from terminals or bulk plants or 
directly from refineries, and usually store the gasoline in underground storage tanks. Gasoline 
service stations are establishments primarily selling gasoline and automotive lubricants. 

Gasoline is by far the largest volume of petroleum product marketed in the 
United States, with a nationwide consumption of 115 billion gallons (434 billion liters) in 
1993. 155 There are presently an estimated 1,300 bulk ter minal s storing gasoline in the 
United States. 156 About half of these terminals receive products from refineries by pipeline 
(pipeline breakout stations), and half receive products by ship or barge delivery (bulk gas-line 
terminals). Most of the terminals (66 percent) are located along the east coast and in the 
Midwest. The remainder are dispersed throughout the country, with locations largely 
determined by population patterns. 

The benzene emission factors presented in the following discussions were 
derived by multiplying AP-42 VOC emission factors for transportation and marketing 157 times 
the fraction of benzene in the vapors emitted. The average weight fraction of benzene in 
gasoline vapors (0.009) was taken from Reference 157. When developing emission estimates, 
the gasoline vapor emission factors should be modified by specific benzene weight fraction in 
the vapor, if available. Also a distinction should be made between winter and summer blends 
of gasoline (a difference in the Reid vapor pressure of the gasoline, which varies from an 
average of 12.8 psi in the winter to an average of 9.3 in non-winter seasons) to account for the 
different benzene fractions present in both. 158 

The transport of gasoline with marine vessels, distribution at bulk plants, and 
distribution at service stations, their associated benzene emissions, and their controls are 
discussed below. 


6-33 



6.4.1 


Benzene Emissions from Loading M arine Vessels 


Benzene can be emitted while crude oil and refinery products (gasoline, 
distillate oil, etc.) are loaded and transported by marine tankers and barges. Loading losses 
are the primary source of evaporative emissions from marine vessel operations. 159 These 
emissions occur as vapors in “empty” cargo tanks are expelled into the atmosphere as liquid is 
added to the cargo tank. The vapors may be composed of residual material left in the “empty” 
cargo tank and/or the material being added to the tank. Therefore, the exact composition of 
the vapors emitted during the loading process may be difficult to predict. 

Benzene emissions from tanker ballasting also occur as a result of vapor 
displacement.. Ballasting emissions occur as the ballast water enters the cargo tanks and 
displace vapors remaining in the tank from the previous cargo. In addition to loading and 
ballasting losses, transit losses occur while the cargo is in transit. 157160 

Volatile organic compound (VOC) emission factors for petroleum liquids for 
marine vessel loading are provided in the EPA document Compilation of Air Pollutant 
Emission Factors (AP-42), Chapter 5 157 and the EPA document VOC/HAP Emissions from 
Marine Vessel Loading Operations - Technical Support Document for Proposed Standards , 159 

Uncontrolled VOC and benzene emission factors for loading gasoline in marine 
vessels are presented in Table 6-12. This table also presents emission factors for tanker 
ballasting losses and transit losses from gasoline marine vessels. 

Table 6-13 presents total organic compound emission factors for marine vessels 
including loading operations, and transit for crude oil, distillate oil, and other fuels. Emissions 
of benzene associated with loading distillate fuel and other fuels are very low, due primarily to 
their low VOC emission factor and benzene content. When developing benzene emission 
estimates, the total organic compound emission factors presented in Table 6-13 should be 
multiplied by specific benzene weight fraction in the fuel vapor, if available. 


6-34 




TABLE 6-12. UNCONTROLLED VOLATILE ORGANIC COMPOUND AND BENZENE EMISSION FACTORS FOR 

LOADING, BALLASTING, AND TRANSIT LOSSES FROM MARINE VESSELS 


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6-35 


b Based on the average weight percent of benzene/VOC ratio of 0.009. 159 

c Ocean barge is a vessel with compartment depth of 40 feet; barge is a vessel with compartment depth of 10-12 feet. 
d Units for this factor are lb/week-1000 gal (mg/week-liter) transported. 









TABLE 6-13. UNCONTROLLED TOTAL ORGANIC COMPOUND EMISSION FACTORS 

FOR PETROLEUM MARINE VESSEL SOURCES 3 















6.4.2 


Benzene Emissions from Bulk Gasoline Plants and Bulk Gasoline Terminals 


i Each operation in which gasoline is transferred or stored is a potential source of 

benzene emissions. At bulk terminals and bulk plants, loading, unloading, and storing 
gasoline are sources of benzene emissions. 

i 

Emissions from Gasoline Loading and Unloading 

The gasoline that is stored in above ground tanks at bulk terminals and bulk 
plants is pumped through loading racks that measure the amount of product. The loading racks 
consist of pumps, meters, and piping to transfer the gasoline or other liquid petroleum 
products. Loading of gasoline into tank trucks can be accomplished by one of three methods: 
splash, top submerged, or bottom loading. Bulk plants and terminals use the same three 
methods for loading gasoline into tank trucks. In splash loading, gasoline is introduced into 
the tank truck directly through a hatch located on the top of the truck. 160 Top submerged 
loading is done by attaching a downspout to the fill pipe so that gasoline is added to the tank 
truck near the bottom of the tank. Bottom loading is the loading of product into the truck tank 
from the bottom. Emissions occur when the product being loaded displaces vapors in the tank 
being filled. Top submerged loading and bottom loading reduce the amount of material 
(including benzene) that is emitted by generating fewer additional vapors during the loading 
process. 160 A majority of facilities loading tank trucks use bottom loading. 

Table 6-14 lists emission factors for gasoline vapor and benzene from gasoline 
loading racks at bulk terminals and bulk plants. 160 The gasoline vapor emission factors were 
taken from Reference 157. The benzene factors were obtained by multiplying the gasoline 
vapor factor by the average benzene content of the vapor (0.009 percent). 158 


6-37 



TABLE 6-14. BENZENE EMISSION FACTORS FOR GASOLINE LOADING RACKS 

AT BULK TERMINALS AND BULK PLANTS 



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6-38 

















Emissions from Storage Tanks 


Storage emissions of benzene at bulk terminals and bulk plants depend on the 
type of storage tank used. A typical bulk terminal may have four or five above ground storage 
tanks with capacities ranging from 400,000 to 4 million gallons (1,500 to 15,000 m 3 ). 160 Most 
tanks in gasoline service are of an external floating roof design. Fixed-roof tanks, still used in 
some areas to store gasoline, use pressure-vacuum vents to operate at a slight internal pressure 
or vacuum and control breathing losses. Some tanks may use vapor balancing or processing 
equipment to control working losses. 

The major types of emissions from fixed-roof tanks are breathing and working 
losses. Breathing loss is the expulsion of vapor from a tank vapor space that has expanded or 
contracted because of daily changes in temperature and barometric pressure. The emissions 
occur in the absence of any liquid level change in the tank. Combined filling and emptying 
losses are called “working losses.” Emptying losses occur when the air that is drawn into the 
tank during liquid removal saturates with hydrocarbon vapor and is expelled when the tank is 
filled. 


A typical external floating-roof tank consists of a cylindrical steel shell equipped 
with a deck or roof that floats on the surface of the stored liquid, rising and falling with the 
liquid level. The liquid surface is completely covered by the floating roof except in the small 
annular space between the roof and the shell. A seal attached to the roof touches the tank wall 
(except for small gaps in some cases) and covers the remaining area. The seal slides against 
the tank wall as the roof is raised or lowered. The floating roof and the seal system serve to 
reduce the evaporative loss of the stored liquid. 

An internal floating-roof tank has both a permanently affixed roof and a roof 
that floats inside the tank on the liquid surface (contact roof), or is supported on pontoons 
several inches above the liquid surface (noncontact roof). The internal floating-roof rises and 
falls with the liquid level, and helps to restrict the evaporation of organic liquids. 


6-39 







The four classes of losses that floating roof tanks experience include withdrawal 
loss, rim seal loss, deck fitting loss, and deck seam loss. Withdrawal losses are caused by the 
stored liquid clinging to the side of the tank following the lowering of the roof as liquid is 
withdrawn. Rim seal losses are caused by leaks at the seal between the roof and the sides of 
the tank. Deck fitting losses are caused by leaks around support columns and deck fittings 
within internal floating roof tanks. Deck seam losses are caused by leaks at the seams where 
panels of a bolted internal floating roof are joined. 

Table 6-15 shows emission factors during both non-winter and winter for 
storage tanks at a typical bulk terminal. 158 The emission factors were derived from AP-42 
equations and a weight fraction of benzene in the vapor of 0.009. 158 Table 6-16 shows 
uncontrolled emission factors for gasoline vapor and benzene for a typical bulk plant. 160 
Table 6-17 shows emission factors during both non-winter and winter months for storage tanks 
at pipeline breakout stations. 158 The emission factor equations in AP-42 are based on the same 
equations contained in the EPA’s computer-based program “TANKS.” Since TANKS is 
regularly updated, the reader should refer to the latest version of the TANKS program 
(version 3.1 at the time this document was finalized) to calculate the latest emission factors for 
fixed- and floating-roof storage tanks. The factors in Tables 6-15 and 6-17 were calculated 
with equations from an earlier version of TANKS and do not represent the latest information 
available. They are presented to show the type of emission factors that can be developed from 
the TANKS program. 

Emissions from Gasoline Tank Trucks 

Gasoline tank trucks have been demonstrated to be major sources of vapor 
leakage. Some vapors may leak uncontrolled to the atmosphere from dome cover assemblies, 
pressure-vacuum (P-V) vents, and vapor collection piping and vents. Other sources of vapor 
leakage on tank trucks that occur less frequently include tank shell flaws, liquid and vapor 
transfer hoses, improperly installed or loosened overfill protection sensors, and vapor 
couplers. This leakage has been estimated to be as high as 100 percent of the vapors w'hich 


6-40 


TABLE 6-15. BENZENE EMISSION PACTORS FOR STORAGE LOSSES AT A 

TYPICAL GASOLINE BULK TERMINAL 


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VAPOR AND BENZENE EMISSION FACTORS FOR A TYPICAL BULK PLANT 


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6-43 


Source: Reference 160. 

* Typical bulk plant with gasoline throughput of 19,000 liters/day (5,000 gallons/day). 
b Based on gasoline emission factor and an average benzene/VOC ratio of 0.009. 
c Calculated using a Stage I control efficiency of 95 percent. 




















TABLE 6-17. BENZENE EMISSION FACTORS FOR STORAGE LOSSES AT A 

TYPICAL PIPELINE BREAKOUT STATION 3 * 1 


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should have been captured and to average 30 percent. Because terminal controls are usually 
found in areas where trucks are required to collect vapors after delivery of product to bulk 
plants or service stations (balance service), the gasoline vapor emission factor associated with 
uncontrolled truck leakage was assumed to be 30 percent of the uncontrolled balance service 
truck loading factor (980 mg/liter x 0.30 = 294 mg/liter). 160 Thus the emission factor for 
benzene emissions from uncontrolled truck leakage is 2.6 mg/liter, based on a benzene/vapor 
ratio of 0.009. 

6.4.3 Benzene Emissions from Service Stations 

The discussion on service station operations is divided into two areas: the 
filling of the underground storage tank (Stage I) and automobile refueling (Stage II). Although 
terminals and bulk plants also have two distinct operations (tank filling and truck loading), the 
filling of the underground tank at the service station ends the wholesale gasoline marketing 
chain. The automobile refueling operations interact directly with the public so that control of 
these operations can be performed by putting control equipment on either the service station or 
the automobile. 

Stage I Emissions at Service Stations 

Normally, gasoline is delivered to service stations in large tank trucks from bulk 
terminals or smaller account trucks from bulk plants. Emissions are generated when 
hydrocarbon vapors in the underground storage tank are displaced to the atmosphere by the 
gasoline being loaded into the tank. As with other loading losses, the quantity of the service 
station tank loading loss depends on several variables, including the quantity of liquid 
transferred, size and length of the fill pipe, the method of filling, the tank configuration and 
gasoline temperature, vapor pressure, and composition. A second source of emissions from 
service station tankage is underground tank breathing. Breathing losses tend to be minimal for 
underground storage tanks due to nearly constant ground temperatures and are primarily the 
result of barometric pressure changes. 


6-46 



Stage II Emissions of Service Stations 


In addition to service station tank loading losses, vehicle refueling operations 
are considered to be a major source of emissions. Vehicle refueling emissions are attributable 
to vapor displaced from the automobile tank by dispensed gasoline and to spillage. The major 
factors affecting the quantity of emissions are dispensed fuel temperature, differential 
temperature between the vehicle's tank temperature and the dispensed fuel temperature, and 
fuel Reid vapor pressure (RVP). 161,162 Several other factors that may have an effect upon 
refueling emissions are: fill rate, amount of residual fuel in the tank, total amount of fill, 
position of nozzle in the fill-neck, and ambient temperature. However, the magnitude of these 
effects is much less than that for any of the major factors mentioned above. 161 

Spillage loss is made up of configurations from prefill and postfill nozzle drip 
and from spit-back and overflow from the vehicle's fuel tank filler pipe during filling. 

Table 6-18 lists the uncontrolled emission factors for a typical gasoline service station. 160,163 
This table incudes an emission factor for displacement losses from vehicle refueling. 

However, the following approach is more accurate to estimate vehicle refueling emissions. 

Emissions can be calculated using MOBILE 5a, EPA’s mobile source emission 
factor computer model. MOBILE 5a uses the following equation: 163 

E r = 264.2 [(-5.909) - 0.0949 (aT) + 0.0884 (T D ) 4- 0.485 (RVP)] 

where: 

E r = Emission rate, mg VOC/0 of liquid loaded 

RVP = Reid vapor pressure, psia (see Table 6-19) 163 

aT = Difference between the temperature of the fuel in the automobile 

tank and the temperature of the dispensed fuel, °F (see 
Table 6-20) 161 

T d = Dispensed fuel temperature, °F (see Table 6-21) 164 

Using this emission factor equation, vehicle refueling emission factors can be derived for 
specific geographic locations and for different seasons of the year. 


6-47 







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6-48 




mobile source emission factor computer model. 












In the absence of specific data, Tables 6-19, 6-20, and 6-21 may be used to 
estimate refueling emissions. Tables 6-19, 6-20, and 6-21 list gasoline RVPs, aT, and T D 
values respectively for the United States as divided into six regions: 


Region 1: Connecticut, Delaware, Elinois, Indiana, Kentucky, Maine, 

Maryland, Massachusetts, Michigan, New Hampshire, 

New Jersey, New York, Ohio, Pennsylvania, Rhode Island, 
Virginia, West Virginia, and Wisconsin. 

Region 2: Alabama. Arkansas, Florida, Georgia, Louisiana, Mississippi, 

North Carolina, South Carolina, and Tennessee. 

Region 3: Arizona, New Mexico, Oklahoma, and Texas. 

Region 4: Colorado, Iowa, Kansas, Minnesota, Missouri, Montana, 

Nebraska, North Dakota, South Dakota, and Wyoming. 

Region 5: California, Nevada, and Utah. 

Region 6: Idaho, Oregon, and Washington. 


6.4.4 


Control Technology for Marine Vessel Loading 


Marine vapor control systems can be divided into two categories: vapor 
recover)' systems and vapor destruction systems. There are a wide variety of vapor recovery 
systems that can be used with vapor collection systems. Most of the vapor recovery systems 
installed to date include refrigeration, carbon adsorption/absorption, or lean oil absorption. 
Three major types of vapor destruction or combustion systems that can operate over the wide 
flow rate and heat content ranges of marine applications are: open flame flares, enclosed flame 
flares, and thermal incinerators. 165 


When selecting a vapor control system for a terminal, the decision on 
recovering the commodity depends on the nature of the VOC stream (expected variability in 
flow rate and hydrocarbon content), and locational factors, such as availability of utilities and 
distance from the tankship or barge to the vapor control system. The primary reason for 
selecting incineration is that many marine terminals load more than one commodity. 159164 


6-49 



TABLE 6-19. RVP LIMITS BY GEOGRAPHIC LOCATION 


State 

Summer 
(Apr.-Sep.) 

Weighted average 

Winter 
(Oct.-Mar.) 

Annual 

Alabama 

8.6 

12.8 

10.6 

Alaska 

13.9 

15.0 

14.3 

Arizona 

8.4 

11.6 

10.0 

Arkansas 

8.5 

13.5 

10.7 

California 

8.6 

12.6 

10.6 

Colorado 

8.6 

13.1 

10.7 

Connecticut 

9.7 

14.5 

12.0 

Delaware 

9.7 

14.3 

11.9 

District of Columbia 

8.8 

14.1 

11.4 

Florida 

8.7 

12.9 

10.7 

Georgia 

8.6 

12.8 

10.7 

Hawaii 

11.5 

11.5. 

11.5 

Idaho 

9.5 

13.2 

11.3 

Illinois 

9.7 

14.2 

12.0 

Indiana 

9.7 

14.3 

11.9 

Iowa 

9.6 

14.2 

11.8 

Kansas 

8.6 

13.1 

10.8 

Kentucky 

9.6 

14.0 

11.7 

Louisiana 

8.6 

12.8 

10.6 

Maine 

9.6 

14.5 

11.9 

Maryland 

9.0 

14.3 

11.6 

Massachusetts 

9.7 

14.5 

12.0 

Michigan 

9.7 

14.5 

12.0 

Minnesota 

9.7 

14.3 

11.8 

Mississippi 

8.6 

12.8 

10.7 

Missouri 

8.7 

13.8 

11.1 

Montana 

9.5 

14.3 

11.7 


(continued) 


6-50 






TABLE 6-19. CONTINUED 


State 

Summer 
(Apr.-Sep.) 

Weighted average 

Winter 
(Oct.-Mar.) 

Annual 

Nebraska 

9.5 

13.5 

11.4 

Nevada 

8.5 

12.5 

10.4 

New Hampshire 

9.7 

14.5 - 

12.0 

New Jersey 

9.7 

14.4 

12.1 

New Mexico 

8.5 

12.4 

10.3 

New York 

9.7 

14.5 

12.0 

North Carolina 

8.8 

13.6 

11.1 

North Dakota 

9.7 

14.2 

11.7 

Ohio 

9.7 

14.3 

11.9 

Oklahoma 

8.6 

12.9 

10.7 

Oregon 

9.0 

13.9 

11.2 

Pennsylvania 

9.7 

14.5 

12.0 

Rhode Island 

• 9.7 

14.5 

12.1 

South Carolina 

9.0 

13.3 

11.0 

South Dakota 

9.5 

13.5 

11.3 

Tennessee 

8.8 

13.6 

11.1 

Texas 

8.5 

12.5 

10.4 

Utah 

8.7 

13.3 

10.9 

Vermont 

9.6 

14.5 

12.0 

Virginia 

8.8 

14.0 

11.3 

Washington 

9.7 

14.3 

11.9 

West Virginia 

9.7 

14.3 

11.9 

Wisconsin 

9.7 

14.3 

11.9 

Wyoming 

9.5 

13.6 

11.5 

Nationwide Annual Average 

9.4 


11.4 

Nonattainment Annual Averaee 

9.2 


11.3 


Source: Reference 163. 


6-51 









TABLE 6-20. SEASONAL VARIATION FOR TEMPERATURE DIFFERENCE 
BETWEEN DISPENSED FUEL AND VEHICLE FUEL TANK 3 


Temperature difference (°F) 



Average 

annual 

Summer 

(Apr.-Sep.) 

Winter 

(Oct.-Mar.) 

5-Month 
Ozone Season 
(May-Sep.) 

2-Month 
Ozone Season 
(July-Aug.) 

National average 

4.4 

8.8 

-0.8 

9.4 

9.9 

Region 1 

5.7 

10.7 

-0.3 

11.5 

12.5 

Region 2 

4.0 

6.8 

0.9 

7.5 

8.2 

Region 3 

3.7 

7.6 

-0.4 

7.1 

7.0 

Region 4 

5.5 

11.7 

-2.4 

12.1 

13.3 

Region 5 

0.1 

3.9 

-4.4 

5.1 

3.2 


* , — .—.. , -- -- — .. - . . . . ., 

Source: Reference 161. 

a Region 6 was omitted, as well as Alaska and Hawaii. 

TABLE 6-21. MONTHLY AVERAGE DISPENSED LIQUID TEMPERATURE (T D ) 


Weighted average 



Summer 

(Apr.-Sep.) 

Winter 

(Oct.-Mar.) 

(Annual) 

National average 

74 

58 

66 

Region 1 

70 

51 

61 

Region 2 

85 

76 

81 

Region 3 

79 

62 

70 

Region 4 

74 

56 

65 

Region 5 

79 

63 

72 

Region 6 

64 

50 

57 

Source: Reference 164. 


6-52 











For additional information on emission controls at marine terminals refer to 
References 159 and 165. 

6.4.5 Control Technology for Gasoline Transfer 

At many bulk terminals and bulk plants, benzene emissions from gasoline 
transfer are controlled by CTG, NSPS, and new MACT programs. Control technologies 
include the use of a vapor processing system in conjunction with a vapor collection system. 160 
Vapor balancing systems, consisting of a pipeline between the vapor spaces of the truck and 
the storage tanks, are closed systems. These systems allow the transfer of displaced vapor into 
the transfer truck as gasoline is put into the storage tank. 160 

Also, these systems collect and recover gasoline vapors from empty, returning 
tank trucks as they are filled with gasoline from storage tanks. The control efficiency of the 
balance system ranges from 93 to 100 percent. 1 ' Figure 6-4 shows a Stage I control vapor 
balance system at a bulk plant. 160 

At service stations, vapor balance systems contain the gasoline vapors within the 
station's underground storage tanks for transfer to empty gasoline tank trucks returning to the 
bulk terminal or bulk plant. Figure 6-5 shows a diagram of a service station vapor balance 
system. 160 For more information on Stage II controls refer to Section 6.4.7. 

6.4.6 Control Technology for Gasoline Storage 

The control technologies for benzene emissions from gasoline storage involve 
upgrading the type of storage tank used or adding a vapor control system. For fixed-roof 
tanks, emissions are most readily controlled by installation of internal floating roofs. An 
internal floating roof reduces the area of exposed liquid surface on the tank and, therefore. 








6-54 


Source: Reference 160. 
































































































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decreases evaporative loss. Installing an internal floating roof in a fixed-roof tank can reduce 
total emissions by 68.5 to 97.8 percent. 160 

For external floating-roof tanks, no control measures have been identified for 
controlling withdrawal losses and emissions. 160 These emissions are functions of the turnover 
rate of the tank and the characteristics of the tank shell. Rim seal losses in external floating 
roof tanks depend on the type of seal. Liquid-mounted seals are more effective than 
vapor-mounted seals in reducing rim seal losses. Metallic shoe seals are more effective than 
vapor-mounted seals but less effective than liquid-mounted seals. 160 

For additional information on control technology for storage tanks refer to the 

EPA documents Compilation of Air Pollutant Emission Factors (AP-42), Chapter 7 33 and 
Reference 158. 

6.4.7 Control Technology for Vehicle Refueling Emissions 

Vehicle refueling emissions are attributable to vapor displaced from the 
automobile tank by dispensed gasoline and to spillage. 

The two basic refueling vapor control alternatives are: control systems on 
service station equipment (Stage II controls), and control systems on vehicles (onboard 
controls). Onboard controls are basically limited to the carbon canister. 

There are currently three types of Stage II systems in limited use in the United 
States: the vapor balance, the hybrid, and the vacuum assist systems. In the vapor balance 
system, gasoline vapor in the automobile fuel tank is displaced by the incoming liquid gasoline 
and is prevented from escaping to the atmosphere at the fillneck/nozzle interface by a flexible 
rubber “boot.” This boot is fitted over the standard nozzle and is attached to a hose similar to 
the liquid hose. The hose is connected to piping which vents to the underground tank. An 
exchange is made (vapor for liquid) as the liquid displaces vapor to the underground storage 


6-56 



tank. The underground storage tank assists this transaction by drawing in a volume of vapor 
equal to the volume of liquid removed. 160 

t The vacuum assist system differs from the balance system in that a “blower” (a 

vacuum pump) is used to provide an extra pull at the nozzle/fillneck interface. Assist systems 
can recover vapors effectively without a tight seal at the nozzle/fillpipe interface because only a 
close fit is necessary. A slight vacuum is maintained at the nozzle/fillneck interface allowing 
air to be drawn into the system and not allowing the vapors to escape. Because of this assist, 
the interface “boot” need not be as tight fitting as with balance systems. Further, the vast 
majority of assist nozzles do not require interlock mechanisms. Assist systems generally have 
vapor passage valves located in the vapor passage somewhere other than in the nozzles, 
resulting in a nozzle which is less bulky and cumbersome than nozzles employed by vapor 
balance systems. 160 

There are four assist systems that are currently available and certified by the 
California Air Resources Board (CARB): the Hasstech, the Healy, the Hirt, and the Amoco 
Bellowless Nozzle System. 163 

The hybrid system borrows from the concepts of both the balance and vacuum 
assist systems. It is designed to enhance vapor recovery at the nozzle/fillneck interface by 
vacuum, while keeping the vacuum low enough so that a minimum level of excess vapor/air is 
returned to the underground storage tank. 

With the hybrid system, a small amount of the liquid gasoline (less than 
10 percent) pumped from the storage tank is routed (before metering) to a restricting nozzle 
called an aspirator. As the gasoline goes through this restricting nozzle, a small vacuum is 
generated. This vacuum is used to draw vapors into the rubber boot at the interface. Because 
the vacuum is so small, very little excess air, if any, is drawn into the boot, hose and 
underground storage tank, and thus there is no need for a secondary processor, such as the 
vacuum assist s incinerator. 


6-57 







Results of the California Air Resources Board certification testing program on 
Stage II vapor recovery systems indicate that all of the Stage II vapor recovery systems 
discussed above are capable of achieving an emission reduction of 95 percent. 160 However, 
efficiencies vary depending upon inspection frequency, maintenance, and number of stations 
exempted. Reference 163 discusses efficiency in more detail. 

Onboard vapor control systems consist of carbon canisters installed on the 
vehicle to control refueling emissions. The carbon canister system adsorbs, on activated 
carbon, the vapors which are displaced from the vehicle fuel tank by the incoming gasoline. 
Such a system first absorbs the emissions released during refueling and subsequently purges 
these vapors from the carbon to the engine carburetor when it is operating. This system is 
essentially an expansion of the present evaporative emissions control system used in all new 
cars to minimize breathing losses from the fuel tank and to control carburetor evaporative 
emissions. However, unlike the present system, a refueling vapor recovery system will require 
a tight seal at the nozzle/fillneck interface during refueling operations to ensure vapors flow 
into the carbon canister and are not lost to the atmosphere. An efficiency of 98 percent has 
been reported for control of automobile refueling losses using onboard control systems. 160 

For additional information on control of vehicle refueling emissions at gasoline 
dispensing facilities refer to Reference 163. 

6.4.8 Re gulatory Analysis 

Gasoline loading emissions at bulk gasoline terminals are regulated by the New 
Source Performance Standards promulgated on August 18, 1983. 166 These standards apply to 
VOC emissions at affected facilities that commenced construction or modification after 
December 17, 1980. The standards regulate bulk gasoline terminals with a throughput greater 
than 75,700 liters per day. 


6-58 



Also, the NESHAP for gasoline distribution that was promulgated on 
December 14, 1994, regulates organic hazardous air pollutant (HAP) emissions (including 
benzene) from gasoline loading and transport operations. The NESHAP covers HAP 
emissions from storage vessels, piping and handling, and loading at bulk gasoline terminals, 
and storage vessels at piping systems that handle the gasoline at pipeline breakout stations. 167 

6.5 PUBLICLY OWNED TREATMENT WORKS 

Publicly owned treatment works (POTWs) treat wastewater from residential, 
institutional, commercial, and industrial facilities. In general, benzene emissions from POTWs 
originate from the benzene content of industrial wastewater that is introduced into POTWs, and 
benzene may be emitted by volatilization at the liquid surface of the wastewater. 

Industrial wastewater sent to POTWs from industrial facilities may be pre¬ 
treated or untreated, depending on State and Federal industrial wastewater quality standards. 
The following discussion describes the various treatment process units at POTWs from which 
benzene may be emitted. 

6.5.1 Process Description of POTWs 

A POTW treats wastewater using physical, chemical, and biological treatment 
processes. Most POTWs are required by Federal and State laws to treat wastewater using 
“primary” treatment methods to remove coarse and suspended solids and “secondary” 
treatment methods to remove biodegradable organics, pathogens, and additional solids. 
Additionally, some POTWs are required to use “tertiary” treatment methods to remove 
refractory organics, nutrients (e.g., phosphorus and nitrogen), dissolved inorganic salts, and 
heavy metals, among other contaminants. As the wastewater is treated, all of the collected 
solids and sludge undergo additional processing at the POTW to reduce sludge volume, 
organic content, and bacterial activity prior to disposal. 


6-59 









The following discussion describes the various process units included in a 
typical POTW facility (shown in Figure 6-6), that uses primary and secondary wastewater 
treatment methods. 168 As discussed in Section 6.6.2, a testing program for organic emissions 
from POTWs documented that benzene is emitted from most of these process units. 

Comminutors 

Comminutors (or shredders) are devices that are used to grind or cut waste 
solids to about one-quarter-inch (6 mm) particles. In one common type of comminutor, the 
untreated wastewater enters a slotted cylinder within which another similar cylinder with 
sharp-edged slots rotates rapidly. As the solids are reduced in size, they pass through the slots 
of the cylinders and move on with the liquid to the treatment plant. Comminution eliminates 
the need to use screens, which collect large solid waste material that must be disposed of 
separately from the sludge. 169 

Aerated Grit Chambers 

Grit chambers are used at many POTWs to remove dense solids (both inorganic 
and organic) present in wastewater (e.g., sand, gravel, glass, coffee grounds). Aerated grit 
chambers work by imparting a helical flow pattern to the sewage by aerating one side of the 
chamber. The aeration allows the dense grit to settle while keeping less dense organic material 
in suspension. Benzene emissions arise from aeration of the wastewater in the grit chamber. 168 

Primary Sedimentation Tanks 

The main function of primary sedimentation tanks is to remove suspended 
material that settles readily from raw sewage. This material includes slower-settling organic 
matter as well as fast-settling grit if the POTW does not have grit removal upstream. 
Additionally, the system removes floatable solids, which are composed mostly of fats and 
grease. The wastewater enters the tank at one end, flows through the tank and under a surface 


6-60 



Commlnutor I—►! Grit I—Sedimentation I—►! Biological I—m S®condery 1 - I—►! Contact I—►! Dechlorination 

Chamber \ Tank Treatment \ C,an,,er Fi,,er * | Tank 


dia-»f-/vnd-660ore 





6-61 


Source: Reference 168. 




































baffle located near the tank's downstream edge, over a weir, and into an effluent channel. 
Sludge collects on the bottom of the tank. A system of scrapers collects the sludge from the 
bottom of the tank and pumps it to gravity sludge thickeners for further treatment. The surface 
baffle skims the surface of the water and collects the floatables for removal and treatment in 

anaerobic digesters. 

Small amounts of benzene are released by volatilization from the quiescent 
section of the tank prior to the weir. Most of the benzene emissions from the primary 
sedimentation tank result from the turbulence that the water undergoes dropping over the weir 
into the outlet conveyance channel. The height of the water drop from the weir is a measure of 
the energy dissipated and may relate to the release of benzene emissions. 168 

Aerobic Biological Treatments 

Aerobic biological treatment involves the use of microorganisms to metabolize 
dissolved and colloidal organic matter in the wastewater in an aerobic environment. Two types 
of processes are used: suspended-growth and attached-growth. The most common 
suspended-growth process used in POTWs is the activated sludge process; the most common 
attached-growth process is the trickling filter. These two types of processes are described 
below. 169 


Activated Sludge Process --In the activated sludge process, a high concentration 
of microorganisms that have settled in the secondary clarifiers (called activated sludge) is 
added to settled wastewater that enters an aerobic tank. The mixture enters an aeration tank, 
where the organisms and wastewater undergo further mixing with a large quantity of air or 
oxygen to maintain an aerobic environment. There are three common types of aeration tanks: 
diffused air, mechanically mixed air, and pure oxygen (which can be diffused or mechanically 
mixed). Diffused air systems aerate the water by bubbling air from the atmosphere through the 
water from the bottom of the tank. Mechanically mixed air systems use mechanical surface 
mixers that float on the water surface. 


6-62 



In pure oxygen systems (which are more likely to be covered systems), pure 
oxygen is fed to either submerged diffusers or to the head space over a tank employing 
mechanical aerators. In diffused air or oxygen systems, the air or oxygen bubbles can strip 
VOC from the liquid phase depending on the concentrations and partial pressures of the 
specific substances. In mechanically mixed systems, the area where the wastewater/activated 
sludge mixture is agitated is a potential source of VOC (benzene) emissions. 168,169 

Trickling Filter -The trickling filter is an aerobic attached-growth treatment 
process that uses microorganisms growing on a solid media to metabolize organic compounds 
in the wastewater. Trickling filter media beds are typically 40 to 100 ft in diameter and 15 to 
40 ft deep. Influent wastewater from the primary sedimentation tank is sprayed on top of the 
media bed. The wastewater is biologically treated as it trickles downward through the media. 
Effluent from the process is collected by the underdrain system and sent to a secondary 
clarifier. Ambient air is blown upward through the media to provide oxygen to sustain 
microbial growth. The exhaust air from the process may contain benzene that was stripped 
from the wastewater during treatment. 168 

Secondary Clarification 

Secondary clarification is a gravity sedimentation process used in wastewater 
treatment to separate out the activated sludge solids from the effluent from the upstream 
biotreatment process. Effluent from the biological treatment process is introduced into the 
clarifier through submerged diffusers. As the wastewater flows through the clarifier tank from 
inlet to outlet weirs, the solids settle to the bottom of the tank while the floatables and scum are 
skimmed off the top. The tank bottom is sloped slightly to the discharge end of the tank to two 
hoppers, where sludge is collected by a chain and flight conveyor system and returned to the 
biological treatment system or to the waste sludge handling system. The quiescent section of 
the tank may release benzene by volatilization from the water surface. However, most of the 
benzene emissions from the secondary clarifier result from the turbulence that the water 
undergoes dropping over the weir into the outlet conveyance channel. In some cases, the weir 


6-63 







is notched, such that the water flows through the notches, falling only a few inches onto a 
support structure. In this latter case, there is much less turbulence in the water, and it is 
expected that there would be fewer emissions of VOC than in the case where the water 
free-falls directly into the collection channel. 165 

Tertiary Filters 

Tertiary filters remove unsettled particles from the wastewater by using enclosed 
(pressure) filters or open (gravity) filters. The filtering medium typically consists of sand and 
anthracite coal, and may consist of one or two grain sizes. To collect activated sludge effluent, 
the filters typically remove particles in the size ranges of 3 to 5 yum and 80 to 90 fj.m. Alum or 
polymer is often added prior to filtration to form a floe and thus increase paniculate removal. 

Cleaning of ternary filters (called backwashing) typically occurs by forcing 
water back through the filter. The backwash water is typically recirculated upstream in the 
plant. Except for the brief periods during backwash, gravity teniary filters have quiescent 
surfaces, and little VOC release would be expected. Pressure filters are totally enclosed, and 
no air emissions occur during filtration from these units. 168 

Chlorine Contact Tanks 

For the purposes of disinfection, chlorine in the form of chlorine gas or calcium 
or sodium hypochlorite is fed into the wastewater just prior to the chlorine contact tank. The 
chlorine contact tank is designed to allow the mixture of chlorine and wastewater to remain in 
contact long enough to adequately kill the target organisms (15 minutes to 2 hours). The 
typical flow pattern is a serpentine pattern, consisting of interior baffle walls within a 
rectangular tank. Although water surfaces are generally quiescent, most chlorine contact tanks 
have weirs at the end of the tank to control water levels in the tank. Depending on the depth of 
fall and flow rate, the turbulence at the weir overflow may result in benzene emissions. 168 


6-64 




Dechlorination Chambers 


Typically, a dechlorination chamber is located adjacent to the chlorine contact 
tank to remove chlorine residual in the disinfected wastewater. Chlorinated effluent from the 
chlorine contact tank flows into the dechlorination chamber through a gate valve. In the 
dechlorination chamber, an S0 2 solution or sodium bisulfate is introduced into the wastewater 
through submerged diffusers. The wastewater is hydraulically mixed as the S0 2 is added. The 
dechlorinated water is discharged from the facility. 168 

Sludge Thickeners 

Sludge thickeners collect primary sludge (from the primary sedimentation tank) 
and waste-activated sludge (from the secondary clarifier) to reduce the volume of the sludge 

| 

prior to treatment in an anaerobic digester. The two most common types of thickening 
processes are gravity sludge thickeners and dissolved air floatation thickeners. These two 
types of thickeners are described below. 168 Additionally, centrifuges are used to thicken sludge 
both prior to and after aerobic digestion. (Centrifuges are discussed below under dewatering 
techniques.) 


Gravity Sludge Thickener -In this process, sludge is thickened by allowing 
heavier sludge panicles to settle. Sludge is pumped into the center of a circular tank from 
below. Heavier solid panicles sink to the bottom of the tank, are removed as thickened 
sludge, and are sent to digesters. Lighter sludge panicles (e.g., greases) float to the surface of 
the tank and are removed into a scum trough, where they are directed to a scum conditioner. 

As sludge is added to the tank, the sludge flows outward radially, and liquid effluent from the 
process flows outward over weirs and into the effluent trough located on the periphery of the 
tank. Typically, this liquid returns to the aeration tanks in the activated sludge process for 
further treatment. 168 


6-65 






Dissolved Air Flotation Thickener -This process is used to float sludge by 
forcing the sludge to rise to the water surface. Sludge is pumped into a circular tank with 
central feed or into a rectangular tank with end feed. As the sludge enters the tank, 
microbubbles are introduced into the sludge by pressurizing in a retention tank a portion of the 
effluent liquid from the tank. Pressurization of the liquid causes the air to be dissolved in the 
liquid phase. After pressurization, the recirculated effluent is mixed with the sludge feed. 
When the pressurized liquid is released to atmospheric pressure, the dissolved air is released 
into the solution in the form of microbubbles. As the sludge and pressurized liquid mix, the 
sludge and air mixture rises to the surface in the form of a sludge blanket. Sludge thickening 
occurs as a result of the sludge blanket and by drainage of entrained water from the sludge 
blanket. Surface skimmers are used to remove the sludge blanket from the water surface for 
further treatment in an anaerobic digester. 

Anaerobic Digestion 

Anaerobic digestion is a biological process conducted in the absence of ffee 
oxygen in which anaerobic and facultative bacteria metabolize organic solids in sludge, 
releasing methane and C0 2 as a by-product. Anaerobic digesters are most commonly 
cylindrical, with a diameter of 20 to 125 ft and a depth of 20 to 40 ft. In most digesters, to 
promote adequate contact between the anaerobic biota and organic matter, the sludge is mixed 
by either internal gas recirculation or by digested sludge recirculation. Additionally, the 
sludge is kept heated to about 95°F (35°C) by either direct steam injection into the sludge or 
by recirculating sludge through an external heat exchanging device. With mixing and heating, 
sludge undergoes digestion for about 15 to 25 days. 168,169 

Most digesters are closed containers under a slight pressure. Under normal 
operation, there should be no direct emissions of benzene to the atmosphere. The digester gas 
produced is typically collected and routed to internal combustion engines to produce steam or 
generate electricity. (Refer to Section 7.5 for information about benzene emissions from an 


6-66 



internal combustion engine fueled with POTW digester gas.) If the digester is not covered or 
the digester gases are not collected, then benzene may be emitted directly from the digester. 168 

Dewatering Techniques 

Sludge dewatering operations involve removal of water from sludges by gravity, 
compression, and evaporation processes. Common methods of dewatering are using a belt 

filter press, a sludge centrifuge, and sludge drying beds. 

Belt Filter Press -Digested sludge is mixed with flocculating cationic polymers 
which aid in the separation of the solids from the water. The flocculated sludge is initially 
spread out horizontally over a moving filter belt that passes under plows that turn the 
sludge/polymer solution, aiding in the dewatering process. After gravity thickening on the 
belt, the partially dewatered sludge is conveyed to and falls into a vertical compression zone, 
where water is squeezed out of the sludge between two filter belts moving concurrently 
through a series of rollers. The filtrate from dewatering is collected and returned to the head 
of the treatment plant for processing. Sludge particles enmeshed in the polyester belt fabric are 
continuously washed off by a highly pressurized spray. The dried sludge (“cake”) product is 
collected and carried to silos for storage. 

Benzene emissions from the belt filter press process may be released from the 
following locations: (1) the gravity section, where liquid sludge is discharged and tilled by 
plows, (2) the filtrate pans, where filtrate cascades down from the belts to the filtrate collection 
channel below, (3) the compression zone, where the sludge is squeezed between the two belts, 
and (4) the drainage sump into which the filtrate and wash water are discharged. 168 

Sludge Centrifuge -Digested or pre-digested sludge mixed with flocculating 
cationic polymers is introduced into a spinning cylinder with a conical end bowl that rotates at 
sufficient velocity to force the solids to the sides of the drum. Inside the bowl, a concentric 
screw conveyor with helical flights turns at a slightly different speed than the rotating drum. 


6-67 






forcing the dewatered solids to a discharge at one end of the centrifuge, while the liquid flows 
over to a weir into a discharge at the other end. The dewatered sludge is collected and 
stored. 168 Benzene emissions may be emitted from the point where the separated liquid flows 
over the weir and is discharged from the centrifuge. 

Sludge Drying Bed -A certain volume of sludge is piped into shallow beds, 
where the sludge is allowed to dry by gravity settling, evaporation, and percolation. Some 
drying beds are equipped with a system for decanting the liquid from the drying bed or 
draining the liquid through a sand bed to a collection pipe. Due to factors such as rainfall, 
ambient temperature, wind speed, relative humidity, amount of sun, and the character of the 
sludge, the drying time varies from 30 to 60 days. 168 These same factors will likely affect the 
level of benzene emissions from the sludge drying beds. 

6.5.2 Benzene Emissions From POTWs 

Under a program called the Pooled Emission Estimation Program (PEEP), 21 
POTW facilities in California were tested for emissions of benzene (among other VOC) from 
18 types of process units commonly included in POTW wastewater treatment processes. With 
the exception of one type of process unit (comminutor controlled with wet scrubber), the 
emissions test data yielded uncontrolled benzene emission factors. On average, three facilities 
were tested for each type of process unit. The types of process units that were tested are 
discussed above in section 6.6.1, and include aerated processes (aerated grit chambers, three 
types of activated sludge units, trickling filters, and dissolved air floatation thickeners), gas 
handling processes (anaerobic digesters and digester gas combustion devices), quiescent basins 
(primary sedimentation tanks, secondary clarifiers, tertiary filters, chlorine contact tanks, 
dechlorination, and gravity thickeners), sludge facilities (belt filter press, sludge centrifuges, 
and sludge drying beds), and other processes (comminutors). 

Based on the data collected by PEEP, emission factors could be developed for 
most of the above process steps in the form of pounds of benzene emitted per million gallons 


6-68 




of wastewater treated at a POTW. One type of process unit tested (mechanically-mixed 
activated sludge) did not yield air emissions of benzene above the detection limit in the tests 
performed; however, benzene was detected in the wastewater treated by the tested units. 
Additionally, a benzene emission factor for the dechlorination process unit could only be 
calculated in the form of pounds of benzene emitted per pound of benzene in the wastewater 
influent to the dechlorination chamber. Refer to Table 6-22 for a listing of the emission 
factors. 3,168 


With one exception, all of the emission factors presented in Table 6-21 represent 
uncontrolled emissions of benzene. However, many facilities employ measures for odor 
control that may also reduce benzene emissions to the atmosphere (see discussion in 
Section 6.6.3). Most of the facilities tested under PEEP did employ odor control methods; 
however, benzene emissions after control were not measured. 

6.5.3 Control Technologies for PQTWs 

In general, the only types of control devices and techniques found at POTWs are 
the scrubbers and covers used to improve the odor of the air released from the process units. 
Using the information provided by PEEP, it could be determined which process units 
commonly employ covers and scrubbers. 

In many cases, aerated grit chambers are covered and vented to a scrubber. 
Primary sedimentation tanks are sometimes covered and vented to a scrubber; however, many 
of these units are uncovered. Activated sludge units may sometimes be completely covered 
and vented to a scrubber or partially covered and vented to the atmosphere. This practice is 
more common if a pure oxygen system is employed. Trickling filter units are sometimes 
covered and vented to a scrubber. Secondary clarifiers may be uncovered or partially covered 
over the weir discharge area with no vents. Tertiary filters are commonly uncovered. 


6-69 



TABLE 6-22. SUMMARY OF BENZENE EMISSION FACTORS FOR POTWs 


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Chlorine contact tanks are either uncovered or partially covered. Dechlorination 
units are often enclosed in a building that vents to a scrubber. Thickeners are commonly 
covered and sometimes vented to a scrubber. Anaerobic digesters are commonly closed under 
a slight pressure, and the gas is sent to an internal combustion engine or boiler to produce 
steam or electricity; however, some digesters may vent to the atmosphere. Belt filter presses 
are commonly enclosed in a building that vents to a scrubber. Sludge centrifuges are 
commonly enclosed and vented to a scrubber. Drying beds are most commonly uncovered. 165 

6.5.4 Regulatory Analysis 

At the present, there are no Federal regulations that apply directly to benzene air 
emissions from POTWs. However, two regulations indirectly apply: the HON and the 
Benzene Waste Operations NESHAP. Both of these apply directly to specific types of 
industrial facilities that may generate wastewater containing benzene. Both regulations 
stipulate that these facilities may comply with the treatment requirements by sending then- 
wastewater to an off-site treatment plant. However, the off-site plant must remove or destroy 
the benzene in the wastewater to the level specified in the regulations. Further information on 
the regulation can be found in Section 4.5.4 of this document. 

6.6 MUNICIPAL SOLID WASTE LANDFILLS 

A municipal solid waste (MSW) landfill unit is a discrete area of land or an 
excavation that receives household waste, but is not a land application unit (i.e. for receiving 
sewage sludge), surface impoundment, injection well, or waste pile. An MSW landfill unit 
may also receive other types of wastes, such as commercial solid waste, nonhazardous sludge, 
and industrial solid waste. Benzene emissions from MSW landfills are expected to originate 
from the non-household sources of MSW. The types of waste potentially accepted by MSW 
landfills include: 


MSW; 


6-72 






Household hazardous waste; 


• Municipal sludge; 

• Municipal waste combustion ash; 

• Infectious waste; 

• Waste tires; 

• Industrial non-hazardous waste; 

• Conditionally exempt small quantity generator hazardous waste; 

• Construction and demolition waste; 

• Agricultural wastes; 

• Oil and gas wastes; and 

• Mining wastes. 

MSW management in the United States is dominated by disposal in landfills. 
Approximately 67 percent of solid waste is landfilled, 16 percent is incinerated, and 17 percent 
is recycled or composted. There were an estimated 5,345 active MSW landfills in the United 
States in 1992. In 1990, active landfills were receiving an estimated 130 million tons 
(118 million Mg) of waste annually., with 55 to 60 percent reported as household waste and 
35 to 45 percent reported as commercial waste. 1 ' 0 

6.6.1 Process Description of MSW Landfills 170 

There are three major designs for municipal landfills: the area method, the 
trench method, and the ramp method. They all utilize a three-step process, which includes 
spreading the waste, compacting the waste, and covering the waste with soil. The area fill 
method involves placing waste on the ground surface or landfill liner, spreading it in layers, 
and compacting it with heavy equipment. A daily soil cover is spread over the compacted 
waste. The trench method entails excavating trenches designed to receive a day’s worth of 


6-73 







waste. The soil from the excavation is often used for cover material and wind breaks. The 
ramp method is typically employed on sloping land, where waste is spread and compacted in a 
manner similar to the area method; however, the cover material obtained is generally from the 
front of the working face of the filling operation. The trench and ramp methods are not 
commonly used, and are not the preferred methods when liners and leachate collection systems 
are utilized or required by law. 

Modem landfill design often incorporates liners constructed of soil 
(e.g., recompacted clay) or synthetics (e.g., high density polyethylene) or both to provide an 
impermeable barrier to leachate (i.e., water that has passed through the landfill) and gas 
migration from the landfill. 

6.6.2 Benzene Emissions from MSW Landfills 

The rate of benzene emissions from a landfill is governed by gas production and 
transport mechanisms. Production mechanisms involve the production of the emission 
constituent in its vapor phase through vaporization, biological decomposition, or chemical 
reaction. Transport mechanisms involve the transportation of benzene in its vapor phase to the 
surface of the landfill, through the air boundary layer above the landfill, and into the 
atmosphere. The three major transport mechanisms that enable transport of benzene in its 
vapor phase are diffusion, convection, and displacement. 170 

Uncontrolled Benzene Emissions 170 

Uncontrolled benzene emissions from a landfill may be estimated by utilizing 
the series of equations provided below. The three equations estimate the following three 
variables: (1) the uncontrolled methane generation rate, (2) the uncontrolled benzene emission 
rate (calculated based on the uncontrolled methane generation rate), and (3) the uncontrolled 
benzene mass emission rate (calculated based on the uncontrolled benzene emission rate). As 


6-74 





indicated, the second equation utilizes the product of the first equation, and the third equation 
utilizes the product of the second equation. 

The uncontrolled CH 4 volumetric generation rate may be estimated for 
individual landfills by using a theoretical first-order kinetic model of CH 4 production 
developed by EPA. This model is known as the Landfill Air Emissions Estimation model, and 
it can be accessed from the EPA's Control Technology Center bulletin board. The Landfill 

Air Emissions Estimation model equation is as follows: 

Q CH4 = L 0 R (e- kc - e-*) 


where: 


Qch4 

4 

R 

e 

k 

c 

t 


Methane volumetric generation rate at time t, m 3 /yr 
Methane generation potential, m 3 CH 4 /Mg refuse 
Average annual acceptance rate of degradable refuse during 
active life, Mg/yr 
Base log, unitless 

Methane generation rate constant, yr' 1 

Time since landfill closure, yrs (c = 0 for active landfills) 

Time since the initial refuse placement, yrs 


Site-specific landfill information is generally available for variables R, c, and t. 
When refuse acceptance rate information is scant or unknown, R can be determined by 
dividing the refuse in place by the age of the landfill. Also, nondegradable refuse should be 
subtracted from the mass of acceptance rate to prevent overestimation of CH 4 generation. The 


average annual acceptance rate should only be estimated by this method when there is 
inadequate information on the actual average acceptance rate. 


Values for variables L 0 and k must be estimated. Estimation of the potential 
CH 4 generation capacity of refuse (LJ is generally treated as a function of the moisture and 
organic content of the refuse. Estimation of the CH 4 generation constant (k) is a function of a 
variety of factors, including moisture, pH, temperature, and other environmental factors, and 


6-75 






landfill operating conditions. Specific CH 4 generation constants can be computed by use of 
EPA Method 2E. 


The Landfill Air Emission Estimation model uses the proposed regulatory (see 
Section 6.6.4) default values for L 0 and k. However, the defaults were developed for 
regulatory compliance purposes. As a result, the model contains conservative L 0 and k default 
values in order to protect human health, to encompass a wide range of landfills, and to 
encourage the use of site-specific data. Therefore, different L 0 and k values may be 
appropriate in estimating landfill emissions for particular landfills and for use in an emissions 
inventory. 


A higher k value of 0.05/yr is appropriate for areas with normal or above 
normal precipitation. An average k value is 0.04/yr. For landfills with drier waste, a k value 
of 0.02/yr is more appropriate. An L 0 value of 125 m 3 /Mg (4,005 fF/ton) refuse is appropriate 
for most landfills. It should be emphasized that in order to comply with the proposed 
regulation (see Section 6.6.4), the model defaults for k and L 0 must be applied as specified in 
the fmal rule. 


Based on the CH 4 volumetric generation rate calculated above, the benzene 
volumetric emission rate from a landfill can be estimated by the following equation: 


Qbz — 2 Qch 4 * C BZ /(lxl0 6 ) 

where: 

Q bz = Benzene volumetric emission rate, m 3 /yr 

Qch 4 = CH 4 volumetric generation rate, m 3 /yr (from the Landfill Air 

Emission Estimation model) 

C BZ = Benzene concentration in landfill gas, ppmv 

2 = Multiplication factor (assumes that approximately 50 percent of 

landfill gas is CH 4 ) 


Uncontrolled emission concentrations of benzene based on a landfill site’s 
history of co-disposal with hazardous wastes are presented in Table 6-23. 3,170 An analysis of 


6-76 


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benzene emissions data based on the co-disposal history of the individual landfills from which 
the concentration data were derived indicates that benzene emissions do vary with the amount 
of hazardous waste co-disposed. These benzene concentrations have already been corrected for 
air infiltration and can be used, when site-specific data are not available, as input parameters 
(for the variable C BZ ) in the above equation for estimating benzene volumetric emission rates 
from landfills. 


Then, based on the benzene volumetric emission rate calculated using the above 
equation, the uncontrolled mass emission rate of benzene from a landfill can be estimated by 
the following equation: 




_78.113_ 

(8.205x10 ' 5 m 3 -atm/mol-°K) (1000 g) (273 + T) 


where: 



T 

78.113 = 


Uncontrolled benzene mass emission rate, kg/yr 
Benzene volumetric emission rate, m 3 /yr 
Temperature of landfill gas, °C 
Molecular weight of benzene 


This equation assumes that the operating pressure of the system is approximately 
1 atmosphere. If the temperature of the landfill gas is not known, a temperature of 25°C is 
recommended. 


Controlled Benzene Emissions 

As discussed in more detail in Section 6.6.3, emissions from landfills are 
typically controlled by installing a gas collection system and destroying the collected gas 
through the use of internal combustion engines, flares, or turbines. The control system for 
landfills consists of two stages, and estimating controlled benzene emissions involves the 
following two steps: (1) estimating the amount of benzene that is not collected by the gas 
collection system, and (2) estimating the amount of collected benzene that is not destroyed by 
the control device. 


6-78 




The amount of benzene that is not collected by the gas collection system may be 
calculated with the following equation: 



Collection Efficiency - 
TOO , 


* I 


BZ 


where: 

UC BZ = Uncollected benzene mass emission rate, kg/yr 

Collection Efficiency = Collection efficiency of the gas collection 

system, % 

I BZ = Uncontrolled benzene mass emission rate, kg/yr 

If the site-specific collection efficiency cannot be determined, one may assume that a gas 
collection system collects 75 percent of the benzene emitted by a landfill. Reported collection 
efficiencies typically range from 60 to 85 percent, with the average of 75 percent being most 
commonly used for estimation of UC BZ . 


The amount of benzene that is not destroyed by the control device may be 

calculated with the following equation: 


ND bz = 


1 - 


Destruction Efficiency 

Too 


* ^BZ ^Cg Z ) 


where: 


nd bz 

Destruction Efficiency 


Non-destroyed benzene mass emission rate, kg/yr 
Destruction efficiency of the control device, % 


Ibz 

UC 


BZ 


Uncontrolled benzene mass emission rate, kg/yr 
Uncollected benzene mass emissions rate, kg/yr 


If the site-specific destruction efficiency of a control device cannot be determined, one may 
assume the destruction efficiencies provided here. Flares have been documented to destroy 


6-79 








89.5 percent of the benzene routed to the flare. Internal combustion engines have been 
documented to destroy 83.8 percent of the benzene routed to the internal combustion engine. 
After promulgation of standards proposed in 1991 (see Section 6.6.4), however, all control 
devices utilized at both new and existing landfills may be required to reduce the 
non-methanogenic organic compounds (NMOCs) in the collected gas by 98 weight percent. 

Alternatively, if the control device utilized is a flare and the heat content of the 
landfill gas is known, the emission factor provided in Table 6-24 may be used to calculate 
non-destroyed benzene emissions. 3 Additionally, if the control device is an industrial boiler, 
refer to Section 7.4 for information regarding controlling benzene emissions from an industrial 
boiler treating landfill gas. 

After UC BZ and ND BZ have been calculated, these two variables may be added 
together to calculate the total benzene mass emission rate after the control system. 

6.6.3 Control Technologies for MSW Landfills 170 

Landfill gas collection systems are either active or passive systems. Active 
collection systems provide a pressure gradient in order to extract landfill gas by use of 
mechanical blowers or compressors. Passive systems allow the natural pressure gradient 
created by the increase in landfill pressure from landfill gas generation to.mobilize the gas for 

collection. 

Landfill gas control and treatment options include (1) combustion of the landfill 
gas, and (2) purification of the landfill gas. Combustion techniques include techniques that do 
not recover energy (e.g., flares and thermal incinerators) and techniques that recover energy 
and generate electricity from the combustion of the landfill gas (e.g., gas turbines and internal 
combustion engines). Boilers can also be employed to recover energy from landfill gas in the 
form of steam. Flares involve an open combustion process that requires oxygen for 
combustion; the flares can be open or enclosed. Thermal incinerators heat an organic chemical 


6-80 



TABLE 6-24. CONTROLLED BENZENE EMISSION FACTOR FOR LANDFILLS 




Control 

Emission Factor 

Emission 

SCC Number 

Emission Source 

Device 

lb/MMBtu (g/kJ) a 

Factor Rating 

5-02-006-01 

Landfill Dump 

Flare 

7.10xl0' 6 (3.05xl0' 9 ) b 

D 


Source: Reference 3. 

* Emission factor is in lb (g) of benzene emitted per MMBtu (kJ) of heat input to the flare. 
b Based on two tests conducted at two landfill sites. 

to a high enough temperature in the presence of sufficient oxygen to oxidize the chemical to 
C0 2 and water. Purification techniques can also be used to process raw landfill gas to pipeline 
quality natural gas by using adsorption, absorption, and membranes. 

6.6.4 Regulatory Analysis 170 

Proposed NSPS and emission guidelines for air emissions from MSW landfills 
for certain new and existing landfills were published in the Federal Register on May 30, 1991, 
and promulgated March 12, 1996. The regulation requires that Best Demonstrated Technology 
be used to reduce MSW landfill emissions from affected new and existing MSW landfills with 
a design capacity greater than 2.8 million tons (2.5 million Mg by mass or 2.5 million cubic 
meters by volume) of MSW and emitting greater than or equal to 55 tons/yr (50 Mg/yr) of 
NMOCs. The MSW landfills that would be affected by the proposed NSPS would be each new 
MSW landfill and each existing MSW landfill that has accepted waste since May 30, 1991, or 
that has capacity available for future use. Control systems would require (1) a well-designed 
and well-operated gas collection system, and (2) a control device capable of reducing NMOCs 
in the collected gas by 98 weight percent. 

6.7 PULP, PAPER, AND PAPERBOARD INDUSTRY 

In the pulp, paper, and paperboard industry, wood pulp is chemically treated by 
dissolving the lignin that binds the cellulose together and then extracting the cellulose to make 
paper and paperboard. Four types of chemical wood pulping processes are practiced in the 


6-81 







United States. Kraft pulping is the most prevalent type of process, accounting for about 
85 percent of pulp production. Three other pulping processes, semi-chemical, soda-mill, and 
acid sulfite, account for 4, 5, and 6 percent of domestic pulp production, respectively. 

Because kraft pulping is the most common type of pulping and the other processes are 
relatively similar to it, kraft pulping will be the focus of this section. More information on the 
other three pulping processes can be found in References 171 and 172. 

The distribution of kraft pulp mills in the United States in 1993 is shown in 
Table 6-25. 171 Kraft pulp mills are located primarily in the southeast, whose forests provide 
over 60 percent of U.S. pulpwood. 

The U.S. EPA is developing benzene emission factors for pulp and papermaking 

processes in conjunction with MACT standards that are under development. Please refer to the 
CHIEF bulletin board for benzene emission factors that will be forthcoming from the MACT 
development process. More information on the MACT effort is given in Section 6.7.2. 

6.7.1 Process Description for Pulp, Paper, and Paperboard Making Processes 

The key unit operations in the kraft pulp and papermaking process include: 

(1) cooking and evaporation, (2) pressure knotting and screening, (3) brown stock washing, 

(4) decker washing and screening, (5) oxygen delignification, (6) pulp storage, (7) chemical 
recovery and causticizing, (8) co-product recovery, (9) bleaching, and (10) paper making. 
Common potential emission points found in the pulp and papermaking process are listed in 
Table 6-26. 173 Each of the key steps, along with their associated emission points, are 
illustrated in the diagram of a typical Kraft pulping and recovery process (Figure 6-7) and 
these are discussed below in more detail. 171 Bleaching, which is frequently used as a final step, 
and papermaking are discussed at the end of this section. 


6-82 



TABLE 6-25. DISTRIBUTION OF KRAFT PULP MILLS IN THE 

UNITED STATES (1993) 


State 


Kraft Pulp Mills 



Alabama 

16 

Arizona 

1 

Arkansas 

7 

California 

4 

Florida 

8 

Georgia 

12 

Idaho 

1 

Kentucky 

2 

Louisiana 

10 

Maine 

7 

Maryland 

1 

Michigan 

3 

Minnesota 

2 

Mississippi 

6 

Montana 

1 

New Hampshire 

1 

North Carolina 

5 

Ohio 

1 

Oklahoma 

1 

Oregon 

7 

Pennsylvania 

3 

South Carolina 

6 

Tennessee 

2 

Texas 

6 

Virginia 

4 

Washington 

7 

Wisconsin 

4 

Total 

126 


Source: Reference 171. 


6-83 













TABLE 6-26. LIST OF COMMON POTENTIAL EMISSION POINTS WITHIN THE 

KRAFT PULP AND PAPERMAKING PROCESS 


Digester relief vents 

Washer filtrate tanks 

Turpentine recovery system vents 

Decker 

Digester blow gas vents 

Screen 

Noncondensible gas system vents 

Weak black liquor storage tank 

Evaporator noncondensible gas vent 

Recovery furnace stack 

Evaporator hotwell gas vent 

Slaker/causticizer vents 

Knotter 

Lime kiln stack 

Brownstock or pulp washer 

Bleach plant vents 

Washer foam tanks 

Papermachine vents 


Source: Reference 173. 


Cooking and Evaporation 

The pulping or cooking process begins with the digester, which is a pressure 
vessel that is used to chemically treat chips and other cellulosic fibrous materials (such as 
straw, bagasse, rags, etc.) under elevated temperature and pressure to separate fibers from 
each other. This digestion process frequently takes place in an aqueous chemical solution 
(frequently a white liquor solution of sodium hydroxide and sodium sulfide). The digestion 
process may be batch or continuous. After cooking the liquor containing the cooking 
chemicals and lignin is separated from the pulp and sent to a series of evaporators for 
concentration. 


The entire digester and black liquor evaporator system includes (a) the outlet to 
the incinerator for the low-volume-high-concentration (LVHC) gases that are commonly 
collected and routed to such an incineration device, (b) chip bin exhaust vents, and (c) other 
miscellaneous digester and evaporator system emission points. These systems were combined 
since all kraft mills collect and incinerate digester relief gases (Vent C), digester blow tank and 
accumulator gases (Vent A [continuous] and Vent B [batch process]), and evaporator 


6-84 





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Figure 6-7. Typical Kraft Pulp-making Process with Chemical Recovery 










































condenser vents (Vent J). The gases at these emission points are assumed to be routed to the 
combustion device and the benzene reduced by 98 percent: 171 

Deknotting and Prewash Screening 

The pulp from the blow tank enters a knotter where knots (pieces of undigested 
wood) are removed prior to pulp washing in order to produce a higher-quality chemical pulp 
(Emission Point D). 171 The pressure knotter and pre-washer screening system includes all the 
equipment following the digester system (i.e., post blow tank) and preceding the first stage of 
brown stock washing. There are two types of knotters typically used in the industry, open and 
pressurized. The air flow across the two types varies. Open knotters have a greater flow and, 
therefore, are expected to have higher emissions than pressurized knotters. Knotter systems 
typically include equipment such as knot drainer hoods, knot tanks, knot elevators, and 
screened stock chests. Not every piece of equipment is necessarily vented to the atmosphere 
(Emission Point D). The emission factor presented is based on the assumption of a pressurized 
knotter and pre-washing screening system. 

Brown Stock Wash 

Pulp that has been through the blow tank and knotter is then washed with water 
in the brownstock washing process. The purpose of washing is to remove black liquor from 
the pulp so as to recover the cooking chemicals sodium and sulfur and to avoid contamination 
during subsequent processing steps. The brown stock washing system includes all the brown 
stock washers, associated filtrate tanks, vacuum pump exhausts, and any interstage storage 
chests that follow pre-washer screening. In washing, water (ffesh or recycled) is used to rinse 
the pulp and recover the black liquor. There are two basic types of brown stock washing 
systems, the rotary vacuum drum system and the more advanced pressure or diffusion washers. 
Emissions from the washing process occur as compounds entrained in the pulp and black liquor 
slurry volatilize (Emission Point E). 


6-86 


The diluted or “weak” black liquor is recovered in a washer filtrate tank and 
sent to the evaporator area. A washer foam tank is typically used to capture the foam 
separated in the filtrate tank. Foam is formed when soap, which is dissolved by the caustic 
cooking liquors, goes through the washing process. In general, defoaming is completed in the 
foam tank using centrifugal or mechanical force to break up the foamed mass. This force 
allows air trapped in the foam mass to vent to the atmosphere from the washer foam tank 
(Emission Point F). The defoamed weak black liquor is routed to a weak black liquor storage 
tank (Emission Point N) before it is typically piped to the evaporator area. 171 

p 

Screening and Decking 

Screening is performed to remove oversized panicles from the pulp slurry after 
washing the pulp and prior to the papermaking process. The decker is a washing and 
thickening unit that follows brown stock washing and precedes oxygen delignification (if 
present), bleaching (if present), or the paper machines. The decker unit is assumed to consist 
of a drum and a filtrate tank, both of which are assumed to be vented to the atmosphere. The 
emissions from each pan of this decker unit (i.e., both the washer and the filtrate tank) fall 
within the range of emissions reported for individually tested decker washers and decker 
filtrate tanks and is therefore assumed to be representative. 

Decker vents may be either hooded (an open space above the decker with a hood 
covering the unit) or well-enclosed (tightly fitted hood around the unit, no open space except 
through the hood). Hooded deckers are likely to have a much greater air flow across the 
decker, and therefore are expected to have greater emissions (Emission Point G). 

Oxygen Delignification 

Following the screening and/or decking, delignification of pulp with oxygen 
(called oxygen delignification) prior to bleaching is sometimes used. By removing more of the 


6-87 



lignin from the pulp, this pretreatment step helps to reduce the amount of chemicals used by 
the bleach plant. 

The oxygen delignification (OD) system begins with the oxygen reactor and 
associated blow tank (Emission Point H). This system includes a series of two washers and/or 
presses following the oxygen reactor blow tank, each with a filtrate tank. An interstage 
storage chest located between the first and second washers and/or presses is also a common 
configuration. 


Pulp Storage Tank 

Pulp storage tanks refers to the large bulk storage tanks following OD (if 

present) or brown stock washers that store the pulp that is to be routed to the bleach plant or to 
the paper machines. One pulp storage tank is assumed to be present for each pulping line. 

Chemical Recovery and Causticizing 

The chemical recovery and causticizing area of the mill is where strong black 
liquor recovered from the evaporators and concentrators is converted into white liquor for 
reuse in the digesters. This system includes all the equipment associated with chemical 
recovery, beginning with the recovery furnace, the smelt dissolving tanks and ending with the 
white liquor clarifier. 

The chemical recovery and causticizing area is an example of a mill system 
where the number of pieces of equipment tested was driving the emissions. In other words, if 
one mill tested all the components of the recovery loop, that mill would show higher emissions 
for the causticizing area system. The causticizing area system can be broken down into the 
following subsystems: 


6-88 


Recovery furnace . Strong black liquor from the multiple effect evaporators is 
concentrated from 50 to about 70 percent solids either in a concentrator or in a direct contact 
evaporator before being fired in a recovery furnace. The organics in the liquor provide the 
energy required to both make steam and to capture the inorganic chemicals as smelt at the 

bottom of the furnace. 

Smelt dissolving tank . Smelt from the recovery furnace is fed into the tank 
where it is dissolved by weak wash. Smelt dissolving tanks are typically equipped with a 
venturi scrubber for particulate control. Weak wash from the lime mud washer is often used 
as the make-up solution in the scrubber, with spent scrubbing solution flowing into the 
dissolving tank. 

Green liquor clarifier . Effluent from the smelt dissolving tank (green liquor) 
enters a clarifier. Dregs are drained off the bottom of the clarifier, and the clarified green 
liquor passes on to a slaker. 

Slaker and causticizers . Green liquor from the green liquor clarifier is 
convened into white liquor by adding lime in the slaker and causticizers. Emissions from the 
causticizers and the slaker are typically routed to a common venturi scrubber with green liquor 
or fresh mill water as the scrubbing medium. 

White liquor clarifier . White liquor is clarified and the clarified white liquor is 
sent to storage. The bottoms from the white liquor clarifier (lime mud) are sent to a mud 
washer. 


Lime mud washer system . Lime mud from the white liquor clarifier is washed 
here with fresh mill water. The wash water effluent from the mud washer is termed weak 
wash which is used in the smelt dissolving tank. The lime mud washer system includes the 
actual washer plus all associated equipment such as dilution tanks, pressure filters, and mix 


6-89 








tanks. If condensates are used as the wash water, the emissions could be much higher, 
depending on the quality of the condensates. 

Lime kiln . The lime kiln accepts washed lime mud and calcines it to produce 
lime. This lime in turn is fed to the slaker, and the cycle is repeated. The lime kiln is 
typically equipped with a venturi scrubber using fresh mill water as the scrubbing medium for 
particulate emission control. Alternatively, particulates may be controlled by an electrostatic 
precipitator (ESP). 

Co-product Recovery 

Turpentine and soap (tall oil) are two saleable coproducts that may be 
byproducts of the pulping process. Turpentine is recovered from digester relief gases when 
resinous softwoods such as pines are pulped. In general, the digester relief gases are vented to 
a condenser to reduce the gas moisture content and to a cyclone separator to remove any small 
wood chips or fines. Emissions are generated as turpentine and water and are separated in a 
decanter. These emissions are released through the turpentine recovery system vent. Tall oils 
are recovered in a reactor, but emissions are expected to be low because the weak black liquor 
has already been stripped of volatiles in the evaporation process (Vent M). 171 

Bleaching 

Bleaching is the process of further delignifying and whitening pulp by 
chemically treating it to alter the coloring matter and to impart a higher brightness. 

To enhance the physical and optical qualities (whiteness and brightness) of the 
pulp, one of two types of chemical bleaching is used. The first type of bleaching, called 
brightening, uses selective chemicals (such as hydrogen peroxide) that destroy 
chromatographic groups but do not materially attack the lignin. Brightening produces a 
product with a temporary brightness (such as newspaper). In the second type (true bleaching), 


6-90 



oxidizing chemicals (such as chlorine, chlorine dioxide, and sodium hypochlorite) are used to 
remove residual lignin, resulting in a high-quality, stable paper pulp. 171 

The most common bleaching and brightening agents are chlorine, chlorine 
dioxide, hydrogen peroxide, oxygen, caustic (sodium hydroxide) and sodium hypochlorite. 
Typically, the pulp is treated with each chemical in a separate stage. One example stage which 
illustrates the use of one bleaching agent is shown in Figure 6-8. 171 Each stage includes a 
tower where the bleaching occurs (Vent A). The washer (Vent B) removes the bleaching 
chemicals and dissolved lignins from the pulp prior to entering the next stage. The seal tank 
(Vent C) collects the washer effluent to be used as wash water in other stages or to be sewered 
(Vent D). 171 


Paper Machine 

Paper machine emissions include all the emissions from the various pieces of 
equipment following pulp storage and/or bleaching that are used to turn the pulp into a finished 
paper product. The data show that the factor driving emissions from paper machines is paper 
type (i.e., unbleached versus bleached). 

Wastewater/Condensate Treatment 

In addition to process vents, emissions also occur from the treatment of 
wastewater or condensates generated during the making of pulp and paper (Emission 
Point O). 171 

6J.2 Benzene Emissions from Pulp. Paper and Papermaking Processes 

* 

EPA published MACT standards for the pulp, paperboard, and papermaking 
industry on April 15, 1998. 173 While the supporting documentation for these standards does 

4 

not specifically call out benzene as a major pollutant from pulp and paper mills, it 


6-91 





Figure 6-8. Typical Down-flow Bleach Tower and Washer 
Source: Reference 171. 


6-92 










































does mention benzene as being emitted from this source and as a pollutant that would be 
affected by VOC reductions achieved by compliance with the standards. 

Emission points may include the digester relief vents, digester blow gas vents, 
brownstock or pulp washer, screen, as well as bleaching and brightening. Once washing has 
occurred, it is expected that benzene would be found in the wastewater, which is recycled for 
use throughout the process. Such uses of this recycled water include as a solvent for digesting 
chemicals, as the pulp digesting medium, as pulp waste water, and as a diluent for screening, 
cleaning, and subsequent pulp processing. Benzene emissions would then be expected from 
each step in the pulping process where this recycled wastewater is used. Note that the extent 
of benzene emissions (as with any HAP) during the pulping process is a function of the level of 
pulp production, type of digestion (batch or continuous), and the type of wood pulped. 

6.8 SYNTHETIC GRAPHITE MANUFACTURING 

Synthetic graphite is a composite of coke aggregate (filler particles), petroleum 
pitch (binder carbon), and pores (generally with a porosity of 20 to 30 percent). Synthetic 
graphite is a highly refractory material that has been thermally stabilized to as high as 5,400°F 
(3,000°C). Graphite is a valuable structural material because it has high resistance to thermal 
shock, does not melt, and possesses structural strength at temperatures well above the melting 
point of most metals and alloys. Applications for synthetic graphite include the following 
industries: aerospace (e.g., nose cones, motor cases, and thermal insulation), chemical (e.g., 
heat exchangers and centrifugal pumps and electrolytic anodes for the production of chlorine 
and aluminum), electrical (e.g., telephone equipment products, electrodes in fuel cells and 
batteries, and contacts for circuit breakers and relays), metallurgical (e.g., electric furnace 

electrodes for the production of iron and steel, furnace linings, ingot molds, and extrusion 

> 

dies), nuclear (e.g., moderators, thermal columns, and fuel elements), and miscellaneous 
(e.g., motion picture projector carbons). 174 


6-93 


The number of facilities manufacturing synthetic graphite in the United States 
was not identified. 

6.8.1 Process Description for Synthetic Graphite Production 

Synthetic graphite is produced from calcined petroleum coke and coal tar pitch 
through a series of processes including crushing, sizing, mixing, cooling, extrudings baking, 
pitch impregnation, rebaking, and graphitization. Throughout the process of thermal 
conversion of organic materials to graphite, the natural chemical driving forces cause the 
growth of larger and larger fused-ring aromatic systems, and ultimately result in the formation 
of the stable hexagonal carbon network of graphite. A process flow diagram of the synthetic 
graphite manufacturing process is provided in Figure 6-9. 174,175 

Calcined petroleum coke (i.e., raw coke that has been heated to temperatures 
above 2,200°F (1,200°C) to remove volatiles and shrink the coke to produce a strong, dense 
particle) is crushed and screened to obtain uniform-sized fractions for the formulation of dry 
ingredient. Coal tar pitch is stored in heated storage tanks and is pumped to the mixing 
process, as needed, as the liquid ingredient. The dry ingredient is weighed and loaded, along 
with a metered amount of coal tar pitch, into a heated mixing cylinder (heated to at least 320°F 
[160°C]), where they are mixed until they form a homogeneous mixture. During the mixing 
process, vapors (Vent A in Figure 6-9) are ducted to a stack where they are discharged to the 
atmosphere. 174,175 


The heated mixture is sent to a cooling cylinder which rotates, cooling the 
mixture with the aid of cooling fans to a temperature slightly above the softening point of the 
binder pitch. Vapors from the cooling process (Vent B in Figure 6-9) are often vented to a PM 
control device before being vented to the atmosphere. 174,175 

The cooled mixture is charged to a hydraulic press, then pressed through a die 
to give the mixture the desired shape and size. The extruded mixture is referred to as “green 


6-94 



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6-95 


Figure 6-9. Process Flow Diagram for Manufacture of Synthetic Graphite 





















































stock.” The green stock is placed in cooling ponds, where it is further cooled and awaits 
shipping to the baking process. 175 

In general, for producing graphite with high-performance applications, the 
baking process consists of three stages: initial baking, pitch impregnation, and rebaking. In 
producing graphite for some lower-performance applications, the pitch impregnation step is 
excluded. This baking process chemically changes the binder pitch within the green stock by 
forming a permanent carbon bond between the coke particles. By using a slow heating rate, 
the baking process removes most of the shrinkage in the product associated with pyrolysis of 
the pitch binder. This procedure avoids cracking during subsequent graphitization where very 
fast firing rates are used. The impregnation step deposits additional coke in the open pores of 
the baked stock, thereby improving the properties of the subsequent graphite product. The 
product (later referred to as “rebaked stock”) is a solid, rigid body that is much harder and 
stronger than the green stock. 174,175 

Initial baking is achieved by placing the green stock into a furnace cell (if a 
recirculating furnace is used) or a can (if a sagger or pit furnace is used) and surrounding the 
stock with a suitable pack media to support the stock. During the baking process, the furnace 
temperature is increased incrementally (e.g., starting at 350 to 400°F [175 to 200°C] and 
ending at 400 to 570 °F (200 to 300 °C]). The furnace temperature varies according to the 
stock. During the initial baking process, fumes (Vent C in Figure 6-9) are often vented to an 
afterburner prior to discharge to the atmosphere. 175 

Baked stock is pre-heated in a pre-heater to a desired temperature prior to 
impregnation with pitch. Fumes from the pre-heater (Vent D in Figure 6-9) are often vented to 
an afterburner before release to the atmosphere. The pre-heated, baked stock is loaded into 
autoclaves where a vacuum is pulled. Heated petroleum pitch (or coal tar) is pumped from 
storage to the autoclave. Vapors from the storage tank for the heated pitch (Vent D in 
Figure 6-9) are often vented to an afterburner prior to their release to the atmosphere. The 
baked stock is impregnated with pitch under increased temperature and pressure. The pitch 


6-96 


impregnated stock is then stored prior to the rebaking process. Many high-performance 
applications of graphite (e.g., nuclear and aerospace applications) require that the baked stock 
be* multiply pitch-treated to achieve the greatest possible assurance of high performance. 174,175 

Rebaking is similar to initial baking. The same types of furnaces are used for 
both baking and rebaking. The pitch impregnated stock is heated to higher temperatures than 
the green stock (e.g., from 210°F [100°C] to 900 to 1,800°F [500 to 1,000°C]). During the 
rebake process, fumes (Vent E in Figure 6-9) are often vented to an afterburner. Off-gases 
from the afterburner are vented to the atmosphere. 174,175 


The last step in the manufacturing process is graphitization. In this step, 
electricity is used to create temperatures, by resistance, high enough to cause physical and 
chemical changes in the rebaked stock (the carbon atoms in the petroleum coke and pitch orient 
into the graphite lattice configuration). As a result of this step, the hard-baked stock becomes 
softer and machinable, the stock becomes an electrical conductor, and impurities vaporize. 174,175 




In the graphitization step, rebaked stock is placed in a furnace, either 
perpendicular or parallel to the direction of the current flow, depending on the type of furnace 
used. Electricity is used to create temperatures in the stock exceeding 4,350°F (2,400°C), and 
preferably 5,070 to 5,450°F (2,800 to 3,000°C). After graphitization, the stock (i.e., 
synthetic graphite) is stored for on-site use or shipment. Fumes from the furnace are vented to 
the atmosphere (Vent F in Figure 6-9). 174,175 


6.8.2 Benzene Emissions from Synthetic Graphite Production 175 

There is limited information currently available about benzene emissions from 
synthetic graphite production plants. Emission factors for the mixing and cooling cylinders 
(Vents A and B in Figure 6-9) are provided in Table 6-27. 175 Additionally, one emission test 
report indicated that benzene is emitted from the initial baking, rebaking, and 


6-97 




TABLE 6-27. EMISSION PACTORS FOR SYNTHETIC GRAPHITE PRODUCTION 


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6-98 













pitch-impregnation processes (Vents C through E in Figure 6-9); however, emission factors 
could not be developed. 175 

6.8.3 Control Technologies for Synthetic Graphite Production 175 

As discussed in Section 6.9.1, afterburners may be used to control emissions of 
unbumed hydrocarbons from the initial baking and rebaking furnace (Vents C and E in 
Figure 6-9), as well as the preheater and heated storage tank used for the pitch impregnation 
process (Vent D in Figure 6-9). Data regarding the use of afterburners in this application were 
not available; however, it is likely that the afterburners would reduce benzene emissions. 
Additionally, an ESP may be used to control particulate emissions from the cooling cylinder; 
however, it is unlikely that an ESP would reduce benzene emissions. 

6.9 CARBON BLACK MANUFACTURE 

The chemical carbon black consists of finely divided carbon produced by the 
thermal decomposition of hydrocarbons in the vapor phase, unlike coke that is produced by the 
pyrolysis of solids. Carbon black is a major industrial chemical used primarily as a reinforcing 
agent in rubber compounds, which accounts for over 90 percent of its use. It is used primarily 
m tires (both original equipment and replacement), which accounts for over 70 percent of its 
use. 176 Other tire-related applications include inner tubes and retreads. Other uses include 
automotive hoses and belts, wire and cable, roofing, pigment in inks and coatings and as a 
plastic stabilizer. 176 As of January 1994, there were 24 carbon black manufacturing facilities in 
the United States. Over 75 percent of all carbon black production occurs in the States of Texas 
and Louisiana (36 and 40 percent, respectively). The location of all facilities and their 
estimated annual production capacities in 1993 are provided in Table 6-28. 177 The manufacture 
of carbon black is of potential concern for benzene emissions because the predominantly used 
production process involves the combustion of natural gas and the high-temperature pyrolysis 
of aromatic liquid hydrocarbons. 


. 6-99 



TABLE 6-28. LOCATIONS AND ANNUAL CAPACITIES OF CARBON BLACK 

PRODUCERS IN 1994 


Company 

Facility Location 

Annual Capacity, 
millions of pounds 
(millions of kg) 

Cabot Corporation 

Franklin, LA 

260(118) 


Pampa, TX 

60 (27) 


Villa Platte, LA 

280(127) 


Waverly, WV 

180 (82) 

Chevron Corporation 

Cedar Bayou, TX 

20 (9) 

Columbian Chemicals Company 

El Dorado, AR 

120 (54) 


Moundsville, WV 

170 (77) 


North Bend, LA 

220(100) 


Ulysses, KS 

85 (39) 

Degussa Corporation 

Arkansas Pass, TX 

180 (82) 


Belpre, OH a 

130 (59) 


New Iberia, LA 

200(91) 

Ebonex Corporation 

Melvindale, MI 

8 (3.6) 

General Carbon Company 

Los Angeles, CA 

1 (0.45) 

Hoover Color Corporation 

Hiwassee, VA 

1 (0.45) 

J.M. Huber Corporation 

Baytown, TX 

225 (102) 


Borger, TX 

175 (79) 


Orange, TX 

135(61) 

Sid Richardson Carbon and Gasoline 

Addis, LA 

145 (66) 

Company 

Big Springs, TX 

115 (52) 


Borger, TX 

275 (125) 

Witco Corporation 

Phoenix City, AL 

60 (27) 


Ponca City, OK 

255(116) 


Sunray, TX 

120(54) 

TOTAL 


3,420(1,551) 


Source: Reference 177. 


a Emissions of 81,000 lb/yr (36,741 kg/yr) of benzene reported for 1992. m 

Note: This listing is subject to change as market conditions change, facility ownership changes, plants are closed ' 
down, etc. The reader should verify the existence of particular facilities by consulting current listings 
and/or the plants themselves. The level of benzene emissions from any given facility is a function of 
variables such as capacity, throughput, and control measures, and should be determined through direct 
contacts with plant personnel. 


6-100 





6.9.1 


Process Description for Carbon Black Manufacture 


Approximately 90 percent of all carbon black produced in the United States is 
manufactured by the oil-fumace process, a schematic of which is given in Figure 6-10. The 
process streams identified in Figure 6-10 are defined in Table 6-29. 178,179 Generally, all 
oil-furnace carbon black plants are similar in overall structure and operation. The most 
pronounced differences in plants are primarily associated with the details of decomposition 
furnace design and raw product processing. 178 

In the oil-fumace process, carbon black is produced by the pyrolysis of an 
atomized liquid hydrocarbon feedstock in a refractory-lined steel furnace. Processing 
temperatures in the steel furnace range from 2,408 to 2,804°F (1,320 to 1,540°C). The heat 
needed to accomplish the desired hydrocarbon decomposition reaction is supplied by the 
combustion of natural gas. 178 

Feed materials used in the oil-fumace process consist of petroleum oil, natural 
gas, and air. Also, small quantities of alkali metal salts may be added to the oil feed to control 
the degree of structure of the carbon black. 179 The ideal raw material for the production of 
modem, high structure carbon blacks is an oil which is highly aromatic; low in sulfur, 
asphaltenes and high molecular weight resins; and substantially ffeeiDf suspended ash, carbon, 
and water. To provide maximum efficiency, the furnace and burner are designed to separate, 
insofar as possible, the heat generating reaction from the carbon forming reaction. Thus, the 
natural gas feed (Stream 2 in Figure 6-10) is burned to completion with preheated air 
(Stream 3) to produce a temperature of 2,408 to 2,804°F (1,320 to 1,540°C). The reactor is 
designed so that this zone of complete combustion attains a swirling motion, and the oil feed 
(Stream 1), preheated to 392 to 698°F (200 to 370°C), is sprayed into the center of the zone. 
Preheating is accomplished by heat exchange with the reactor effluent and/or by means of a 
gas-fired heater. The oil is cracked to carbon and hydrogen with side reactions producing 
carbon oxides, water, methane, acetylene and other hydrocarbon products. The heat 


6-101 



ATMOSPHERIC EMISSIONS 


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6-102 


Figure 6-10. Process Diagram for an Oil-Furnace Carbon Black Plant 


























































































TABLE 6-29. STREAM CODES FOR THE OIL-FURNACE PROCESS 

ILLUSTRATED IN FIGURE 6-10 


Stream 

Identification 

Stream 

Identification 

1 

Oil feed 

21 

Carbon black from cyclone 

2 

Natural gas feed 

22 

Surge bin vent 

3 

Air to reactor 

23 

Carbon black to pelletizer 

4 

Quench water 

24 

Water to pelletizer 

5 

Reactor effluent 

25 

Pelletizer effluent 

6 

Gas to oil preheater 

26 

Dryer direct heat source vent 

7 

Water to quench tower 

27 

Dryer bag filter vent 

8 

Quench tower effluent 

28 

Carbon black from dryer bag filter 

9 

Bag filter effluent 

29 

Dryer indirect heat source vent 

10 

Vent gas purge for dryer fuel 

30 

Hot gases to dryer 

11 

Main process vent gas 

31 

Dried carbon black 

12 

Vent gas to incinerator 

32 

Screened carbon black 

13 

Incinerator stack gas 

33 

Carbon black recvcle 

j 

14 

Recovered carbon black 

34 

Storage bin vent gas 

15 

Carbon black to micropulverizer 

35 

Bagging system vent gas 

16 

Pneumatic conveyor system 

36 

Vacuum cleanup system vent gas 

17 

Cyclone vent gas recycle 

37 

Dryer vent gas 

18 

Cyclone vent gas 

38 

Fugitive emissions 

19 

Pneumatic system vent gas 

39 

Oil storage tank vent gas 

20 

Carbon black from bag filter 




Source: Reference 178. 


6-103 







transfer from the hot combustion gases to the atomized oil is enhanced by highly turbulent flow 
in the reactor. 179 

The reactor converts 35 to 65 percent of the feedstock carbon content to carbon 
black, depending on the feed composition and the grade of black being produced. The yields 
are lower for the smaller particle size grades of black. Variables that can be adjusted to 
produce a given grade of black include operating temperature, fuel concentration, space 
velocity in the reaction zone, and reactor geometry (which influences the degree of turbulence 
in the reactor). A typical set of reactor operating conditions for high abrasion furnace carbon 
black is given in Table 6-30. 179 

The hot combustion gases and suspended carbon black are cooled to about 
1004°F (540 °C) by a direct water spray in the quench area, which is located near the reactor 
outlet. The reactor effluent (Stream 5 in Figure 6-10) is further cooled by heat exchange in the 
air and oil preheaters. It is then sent to a quench tower where direct water sprays finally 
reduce the stream temperature to 446 °F (230°C). 

Carbon black is recovered from the reactor effluent stream by means of a bag 
filter unit. The raw carbon black collected in the bag filter unit must be further processed to 
become a marketable product. After passing through the pulverizer, the black has a bulk 
density of 1.50 to 3.68 lb/ft 3 (24 to 59 kg/m 3 ), and it is too fluffy and dusty to be transported. 

It is therefore converted into pellets or beads with a bulk density of 6.06 to 10.68 lb/ft 3 (97 to 
171 kg/m 3 ). In this form, it is dust-free and sufficiently compacted for shipment. 

6.9.2 Benzene Emissions from Carbon Black Manufacture 

Although no emission factors are readily available for benzene from carbon 
black manufacture, one carbon black manufacturer with annual capacity of 130 million pounds 
(59 million kg) using the oil-furnace process reported benzene emissions of 81,000 lb/yr 
(36,741 kg/yr) for 1992, which translates to 6.23X10* 4 lb (2.83xl0‘ 4 kg) benzene per lb (kg) 


6-104 



TABLE 6-30. TYPICAL OPERATING CONDITIONS FOR CARBON BLACK 
MANUFACTURE (HIGH ABRASION FURNACE) 


Parameter 

Rate of oil feed 

Preheat temperature of oil 

Rate of air feed 

Rate of natural gas feed 

Furnace temperature in reaction zone 

Rate of carbon black production 

Yield of black (based on carbon in oil feed) 

Source: Reference 179. 


Value 

27 ft 3 /hr (0.76 m 3 /hr) 
550°F (288°C) 
234,944 ft 3 /hr (6,653 m 3 /hr) 
22,001 ftVhr (623 m 3 /hr) 
2,552°F (1,400°C) 

860 lb/hr (390 kg/hr) 

60 percent 


carbon black produced. No regulations applicable to carbon black manufacture were identified 
that would affect benzene emissions. The emission factor is given in Table 6-31. 111 


TABLE 6-31. EMISSION FACTOR FOR CARBON BLACK MANUFACTURE 


SCC Number Description 

Emission Factor 
(lb benzene/lb carbon black) 

Emission 
Factor Rating 

Oil Furnace Process 

6.23x10"* 



Source: Reference 111. 


6.10 RAYON-BASED CARBON FIBER MANUFACTURE 


Rayon-based carbon fibers are used primarily in cloth for aerospace 
applications, including phenolic impregnated heat shields and in carbon-carbon composites for 
missile parts and aircraft brakes. 180 Due to their high carbon content, these fibers remain 
stable at very high temperatures. 

A list of U.S. producers of rayon-based carbon fibers is given in Table 6-32. 177 


6-105 








TABLE 6-32. RAYON-BASED CARBON FIBER MANUFACTURERS 


Manufacturer 

Location 

Amoco Performance Products, Inc. 

Greenville, SC 

BP Chemicals (Hitco) Inc. 

Gardena, CA 

Fibers and Materials Division 


Polycarbon, Inc. 

Valencia, CA 


Source: Reference 177. 

6.10.1 Process Description for the Ravon-Based Carbon Fiber Manufacturing Industry 

There are three steps in the production process of rayon-based carbon cloth: 

• Preparation and heat treating; 

• Carbonization; and 

• High heat treatment (optional). 180 

In the preparation and heat treating step, the rayon-based cloth is heated at 390 to 660°F (200 
to 350°C). Water is driven off (50 to 60 percent weight loss) during this step to form a char 
with thermal stability. In the carbonization step, the cloth is heated to 1,800 to 3,600°F 
(1,000 to 2,000°C), where additional weight is lost and the beginnings of a carbon layer 
structure is formed. To produce a high strength rayon-based fiber, a third step is needed. 

The cloth is stretched and heat treated at temperatures near 5,400°F (3,000°C). 180 


6-106 







6 . 10.2 


Benzene Emissions from the Ravon-Based Carbon Fiber Manufacturing Industry 


Benzene emissions occur from the exhaust stack of the carbon fabric dryer, 
which is used in carbonization of the heat treated rayon. 180 An emission factor for this source 

is given in Table 6-33. 181 

6.10.3 Controls and Regulatory Analysis 

No controls or regulations were identified for the rayon-based carbon fiber 
manufacturing industry. 

6.11 ALUMINUM CASTING 

The aluminum casting industry produces aluminum products, such as aluminum 
pans for marine outboard motors, from cast molds. Sections 6.11.1 through 6.12.3 describe 
the aluminum casting process, benzene emissions resulting from this process, and air emission 
control devices utilized in the process to reduce benzene emissions. 

The number of aluminum casting facilities in the United States was not 

identified. 

6.11.1 Process Description for Aluminum Casting Facilities 

A common method for making the mold for aluminum motor parts is to utilize 
polystyrene foam patterns or “positives” of the desired metal part. The basic principle of the 
casting operation involves the replacement of the polystyrene pattern held within a sand mold 
with molten metal to form the metal casting. Figure 6-11 presents a simplified flow diagram 
for a typical aluminum casting facility utilizing polystyrene patterns. 


6-107 






TABLE 6-33. EMISSION FACTOR FOR RAYON-BASED CARBON MANUFACTURE 


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6-108 














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The aluminum casting process essentially consists of four stages: (1) mold 
assembly, (2) casting (i.e., mold pouring, mold cooling, and cast extraction), (3) cast cleaning 
and finishing (i.e., casting shakeout, cast cooling, and cast cleaning and finishing), and 
(4) sand handling (i.e., sand screening and cleaning). A polystyrene foam pattern is first 
coated with a thin layer of ceramic material for stability. The polystyrene foam pattern is 
placed within a metal flask. Sand is poured into the flask, surrounding and covering the 
pattern. The sand is compacted around the polystyrene pattern to form the mold. Low levels 
of benzene may be emitted from the sand fill operation, depending on the residue of organic 
matter remaining on the sand recycled from the casting shakeout process step. These 
emissions may be collected in a fume hood and vented to the atmosphere (Vent A in 
Figure 6-11). 


The metal flask is moved to the pouring station where molten aluminum is 
poured into the mold. The foam vaporizes as it is displaced by the molten aluminum, which 
fills the cavitv left within the sand mold. A majority of the foam vapors migrate into the sand 
and remain trapped in the sand until the casting shakeout process. Some of the vapors are 
released during the mold pouring event. These vapors are collected in a fume hood and vented 
to the atmosphere (Vent B in Figure 6-11). 

The poured molds are conveyed within the flasks along a cooling conveyor, 
allowing the aluminum casting to harden. The cooling process may result in benzene 
emissions (as depicted as Vent C in Figure 6-11). 

When the casting has formed and cooled sufficiently, the cast is extracted from 
the metal flask. Benzene may be emitted from this process step. The emissions are captured 
and vented to the atmosphere (Vent D in Figure 6-11). 

The casting and flask are moved to the casting shake-out area, where sand used 
in forming the mold is dumped from the flask and removed from the casting by utilizing 
vibration to loosen the compacted sand. The collected sand (including pieces of molding) are 


6-110 


shaken, breaking up the sand mold. The majority of benzene emissions occur during this step. 
Vapors released by breaking the sand molds are captured and either treated with a catalytic 
incinerator or released to the atmosphere (Vent E in Figure 6-11). 

The shaken sand is sent through a screen, then transported to a cleaning process 
for removal of remaining residue, such as a fluidized bed. Benzene emissions may be emitted 
during these process steps (depicted as Vents F and G in Figure 6-11). The cleaned sand is 
then transported to storage for reuse in the process. 

Meanwhile, the casting, which has just undergone shakeout, is sent through a 
series of cooling, cleaning, and finishing steps to produce a final product. Benzene may be 

emitted from these process steps. The final products are stored to await shipping off-site. 

6.11.2 Benzene Emissions From Aluminum Metal Casting 

Benzene emissions from aluminum metal casting are produced by the 
vaporization of the polystyrene foam patterns used to form the molds, resulting from contact of 
the foam with molten aluminum. As described in Section 6.11.1, the polystyrene foam vapors 
migrate into the sand inside the mold, becoming trapped in the sand mold. As a result, most 
benzene emissions from the process are associated with sand handling activities, such as 
casting shake-out and sand screening. However, additional benzene is emitted from the casting 
steps, including mold pouring, mold cooling, and cast extraction. 

Two test reports from two aluminum casting facilities were used to develop 
benzene emission factors. 182,183 Both facilities utilized polystyrene foam patterns in their 
casting operations. One facility was equipped with a catalytic incinerator on its casting 
shakeout operation and a fabric filter on its sand cleaning operation (utilizing a fluidized bed 
for sand cleaning). 183 The other facility was equipped with fabric filters on its mold assembly 
operation (i.e., filling the flask with sand), cast extraction, casting shakeout, and sand 
screenmg operations. 


6-111 




General facility benzene emissions were measured at the two facilities. For one 
facility, general facility emissions consisted of emissions from the mold assembly, cast 
extraction, casting shakeout, sand screening, and sand storage operations, all of which were 
controlled by fabric filters. 182 For the other facility, general facility emissions consisted of 
emissions from the mold assembly, mold pouring, cast extraction, casting shakeout, and sand 
cleaning operations, and only the cleaning operation was controlled with a fabric filter. 183 
Additionally, benzene emissions from the casting shakeout operation were measured both 
before and after the catalytic incinerator, yielding a benzene control efficiency of 89 percent. 183 
The emission factors associated with these emission data are shown in Table 6-34. 181 

6.11.3 Control Technologies for Aluminum Casting Operations 

Fabric filters are most commonly utilized for controlling emissions from 
aluminum casting operations; however, these control devices are not utilized for controlling 
benzene emissions but are rather used to control fugitive dust emissions from sand handling. 
The only control device identified for controlling benzene emissions is a catalytic incinerator. 
As specified in Section 6.12.2, it has been demonstrated that catalytic incinerators achieve 
89 percent reduction in benzene emissions. 

No regulations were identified that control emissions of benzene from aluminum 
casting operations. However, a MACT standard for control of HAPs from secondary 
aluminum facilities is currently underway. 

6.12 ASPHALT ROOFING MANUFACTURING 

The asphaltic material that is obtained toward the end of the process of 
fractional distillation of crude oil is mainly used as asphalt paving concrete (discussed in 
Section 7.9) and for asphalt roofing. The asphalt roofing manufacturing process and the 
emissions associated with its manufacture are described in this section. 


6-112 



TABLE 6-34. EMISSION FACTORS FOR ALUMINUM CASTING 


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6-113 















In 1992, there were 98 asphalt roofing manufacturing plants operating in the 
United States. A list of all current facilities, as identified by the Asphalt Roofing 
Manufacturers Association, is provided in Table 6-35. 184 Total national production in 1993 of 
asphalt roofing materials (saturated felts) was estimated at 557,487 tons (505,749 Mg). 184 
States containing a relatively significant number of roofing plants include California (14), 

Texas (14), Ohio (6), and Alabama (5). These four states contain approximately 40 percent of 
the total number of roofing facilities. The majority of all plants nationwide are located in 
urban as opposed to rural areas. 


6.12.1 Process Description 

The production of asphalt roofing materials is common owing to the widespread 
usage of these materials in the United States. The asphalt roofing industry manufactures 
asphalt-saturated felt rolls, shingles, roll roofing with mineral granules on the surface, and 
smooth roll roofing, which may contain a small amount of mineral dust or mica on the surface. 
Most of these products are used in roof construction, but small quantities are used in walls and 
other building applications. 185 


The asphaltic material derived from crude oil and used to make asphalt roofing 
products is also called asphalt flux. The handling and storing of asphalt flux is a potential 
source of benzene emissions. Asphalt is normally delivered to an asphalt roofing plant in bulk 
by pipeline, tanker truck, or railcar. Bulk asphalt delivered in liquid form may range in 
temperature from 200 to 400 °F (93 to 204 °C), depending on the type of asphalt and local 


practice 


186-188 


With bulk liquid asphalt, the most common method of unloading is to couple a 
flexible pipe to the tanker and pump the asphalt directly into the appropriate storage tanks. 
The tanker cover is partially open during the transfer. Because this is a closed system, the 


6-114 



TABLE 6-35. ASPHALT ROOFING MANUFACTURERS 


Company 

Roofing Plant Location 

Allied-Signal Incorporated 

Detroit, MI 

Fairfield, AL 

Ironton, OH 

Bird Incorported 

Norwood, MA 

The Celotex Corporation 

Camden, AR 

Fremont, CA 

Birmingham, AL 

Goldsboro, NC 

Houston, TX 

Lockland, OH 

Perth Amboy, NJ 

San Antonio, TX 

Los Angeles, CA 

Memphis, TN 

Certainteed Corporation 

Shakopee, MN 

Oxford, NC 

Milan, OH 

Llk Lorportion ot America 

Ennis, TX 

Tuscaloosa, AL 

Fields Corporation 

Kent, WA 

Tacoma, WA 

GAF Building Materials, Inc. 

Baltimore, MD 

Dallas, TX 

Erie, PA 


Fontana, CA 

Millis, MA 

Minneapolis, MN 


Mobile, AL 

Mount Vernon, IN 

Savannah, GA 

Tampa, FL 

Gate Roofing Manufacturing, Inc. 

Green Cove Springs, FL 

Georgia-Pacific Corporation 

Ardmore, OK 

Daingerfield, TX 

Franklin, OH 

Hampton, GA 


Quakertown, PA 


(continued) 


6-115 







TABLE 6-35. CONTINUED 


Company 

Roofing Plant Location 

Globe Building Materials 

Whiting, IN 

St. Paul, MN 

Chester, WV 

GS Roofing Products Company, Inc. 

Charleston, SC 


Ennis, TX 

Little Rock, AR 

Martinez, CA 

Peachtree City. GA 

Portland, OR 

Shreveport, LA 

Wilmington, CA 

Herbert Malarkey Roofing Company 

Portland, OR 

IKO Chicago Incorporated 

Chicago, IL 

IKO Production Incorporated 

Franklin, OH 

Wilmington, DE 

KopDers Industries, Incorporated 

Birmingham, AL 

Chicago, IL 

Follensbee, WV 

Houston, TX 

Leatherback Industries 

Alburquerque, NM 

Hollister, CA 

Lunday-Thagard Company 

South Gate, CA 

Manville Sales Corporation 

Fort Worth, TX 

Pittsburg, CA 

Savannah, GA 

Waukegan, IL 

Neste Oil Services 

Belton, TX 

Calexico, CA 

Fresno, CA 

Houston, TX 

Long Beach, CA 

Pittsburg, CA 

Salt Lake City, UT 

San Diego T CA 


(continued) 


6-116 





TABLE 6-35. CONTINUED 


Company 

Owens-Coming Fiberglas Corporation 


PABCO Roofmg Products 


1AMKO Asphalt rroQucis, incorporated 


TARCO, Incorporated 
U.S. Intec, Incorporated 


Source: Reference 184. 


Roofing Plant Location 

Atlanta, GA 
Brookville, IN 
Compton, CA 
Denver, CO 
Detroit, MI 
Houston, TX 
Irving, TX 
Jacksonville, FL 
Jessup, MD 
Kearny, NJ 
Medina, OH 
Memphis, TN 
Minneapolis, MN 
Morehead City, NC 
Oklahoma City, OK 
Portland, OR 

Richmond, CA 
Tacoma, WA 

Dallas, TX 

Frederick, MD 
Joplin. MO 
Phillipsburg, KS 
Tuscaloosa, AL 

North Little Rock, AR 
Belton, TX 

Corvallis, OR 
Monroe, GA 


.6-117 






only potential sources of emissions are the tanker and the storage tanks. The magnitude of the 
emissions from the tanker is at least partially dependent on how far the cover is opened. 

Another unloading procedure, of which there are numerous variations, is to 
pump the hot asphalt into a large open funnel that is connected to a surge tank. From the surge 
tanks, the asphalt is pumped directly into storage tanks. Emission sources under the surge tank 
configuration are the tanker, the interface between the tanker and the surge tank, the surge 
tank, and the storage tanks. The quantity of emissions depends on the asphalt's temperature 
and characteristics. 

After delivery, asphalt flux is usually stored at 124 to 174°F (51 to 79°C), 
although storage temperatures of up to 450°F (232°C) have been noted. The lower 
temperatures are usually maintained with steam coils in the tanks. Oil- or gas-fired preheaters 
are used to maintain the asphalt flux at temperatures above 200°F (93 X). 186 * 188 

Asphalt is transferred within a roofing plant by closed pipeline. Barring leaks, 
the only potential emissions sources are at the end-points of the pipes. These end-points are 
the storage tanks, the asphalt heaters (if not the closed tube type), and the air-blowing stills. 

Asphalt flux is used to make two roofing grades of asphalt: saturant and 
coating. Saturant and coating asphalts are primarily distinguished by the differences in then- 
softening points. The softening point of saturant asphalts is between 104 to 165°F (40 and 
74°C); coating asphalts soften at about 230°F (110°C). These softening points are achieved 
by “blowing” hot asphalt flux, that is, by blowing air through tanks of hot asphalt flux. 

The configuration of a typical air-blowing operation is shown in Figure 6-12. 185 
This operation consists primarily of a blowing still, which is a tank with a sparger fitted near 
its base. The purpose of the sparger is to increase contact between the blowing air and the 
asphalt. Air is forced through holes in the sparger into a tank of hot (400 to 470°F [204 to 
243 °C]) asphalt flux. The air rises through the asphalt and initiates an exothermic oxidation 


6-118 



KNOCKOUT BOX 
OR CYCLONE 



ASPHALT FLUX 
STORAGE TANK 


Figure 6-12. Asphalt Blowing Process Flow Diagram 


Source: Reference 185. 


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6-119 


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reaction. Oxidizing the asphalt has the effect of raising its softening temperature, reducing 
penetration, and modifying other characteristics. Inorganic salts such as ferric chloride (FeCl 3 ) 
may be used as catalysts added to the asphalt flux during air blowing to better facilitate these 
transformations. 185 

The time required for air blowing of asphalt depends on a number of factors 
including the characteristics of the asphalt flux, the characteristics desired for the finished 
product, the reaction temperature, the type of still used, the air injection rate, and the 
efficiency with which the air entering the still is dispersed throughout the asphalt. Blowing 
times may vary in duration from 30 minutes to 12 hours, with typical times from 1 to 
4.5 hours. 185 - 186 

Asphalt blowing is a highly temperature-dependent process because the rate of 
oxidation increases rapidly with increases in temperature. Asphalt is preheated to 400 to 
470°F (204 to 2i?°C) before blowing is initiated to ensure that the oxidation process will start 
an acceptable rate. Conversion does take place at lower temperatures but is much slower. 
Because of the exothermic nature of the reaction, the asphalt temperature rises as blowing 
proceeds. This, in turn, further increases the reaction rate. Asphalt temperature is normally 
kept at about 500 °F (260 °C) during blowing by spraying water onto the surface of the asphalt, 
although external cooling may also be used to remove the heat of reaction. The allowable 
upper limit to the reaction temperature is dictated by safety considerations, with the maximum 
temperature of the asphalt usually kept at least 50°F (28°C) below the flash point of the asphalt 
being blown. 186 


The design and location of the sparger in the blowing still governs how much of 
the asphalt surface area is physically contacted by the injected air, and the vertical height of the 
still determines the time span of this contact. Vertical stills, because of their greater head 
(asphalt height), require less air flow for the same amount of asphalt-air contact. Both vertical 
and horizontal stills are used for asphalt blowing, but in new construction, the vertical type is 
preferred by the industry because of the increased asphalt-air contact and consequent reduction 


6-120 


in blowing times. 186 Also, asphalt losses from vertical stills are reported to be less than those 
from horizontal stills. All recent blowing still installations have been of the vertical type. 

Asphalt blowing can be either a batch process or a continuous operation; 
however, the majority of facilities use a batch process. Asphalt flux is sometimes blown by 
the oil refiner or asphalt processor to meet the roofing manufacturer's specifications. Many 
roofmg manufacturers, however, purchase the flux and carry out their own blowing. 

Blown asphalt (saturant and coating asphalt) is used to produce asphalt felt and 
coated asphalt roofmg and siding products in the processes depicted in Figures 6-13 and 
6-14. 185 The processes are identical up to the point where the material is to be coated. A roll 
of felt is installed on the felt reel and unwound onto a dry floating looper. The dry floating 
looper provides a reservoir of felt material to match the intermittent operation of the felt roller 
to the continuous operation of the line. Felt is unwound from the roll at a faster rate than is 
reoui r ed hv the line with the excess being stored in the drv looper. The flow of felt to the line 

A » w v 1 

and the tension on the material is kept constant by raising the top set of rollers and increasing 
looper capacity. The opposite action occurs when a new roll is being put on the felt reel and 
spliced in, and the felt supply ceases temporarily. There are no benzene emissions generated 

in this processing step. 186 

Following the dry looper, the felt enters the saturator, where moisture is driven 
out and the felt fibers and intervening spaces are filled with saturant asphalt. (If a fiberglass 
mat web is used instead of felt, the saturation step and the subsequent drying-in process are 
bypassed.) The saturator also contains a looper arrangement, which is almost totally 
submerged in a tank of asphalt maintained at a temperature of 450 to 500 °F (232 to 260 °C). 
The absorbed asphalt increases the sheet or web weight by about 150 percent. At some plants, 
the felt is sprayed on one side with asphalt to drive out the moisture prior to dipping. This 
approach reportedly results in higher benzene emissions than does use of the dip process 
alone. 186 The saturator is a significant benzene emissions source within the asphalt roofing 
process. 


6-121 



VENT TO CONTROL 



Source: Reference 185. 


6-122 


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Figure 6-14. Organic Shingle and Roll Manufacturing Process Flow Diagram 


Source: Reference 185. 


6-123 


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The saturated felt then passes through drying-in drums and onto the wet looper, 
sometimes called the hot looper. The drying-in drums press surface saturant into the felt. 
Depending on the required final product, additional saturant may also be added at this point. 
The amount of absorption depends on the viscosity of the asphalt and the length of time the 
asphalt remains fluid. The wet looper increases absorption by providing time for the saturant 
asphalt to penetrate the felt. The wet looper operation has been shown to be a significant 
source of organic particulate emissions within the asphalt roofing process; however, the 
portion that is benzene has not been defined. 186,187 

If saturated felt is being produced, the sheet passes directly to the cool-down 
section. For surfaced roofmg products, however, the saturated felt is carried to the coater 
station, where a stabilized asphalt coating is applied to both the top and bottom surfaces. 
Stabilized coating contains a mineral stabilizer and a harder, more viscous coating asphalt that 
has a higher softening point than saturant asphalt. The coating asphalt and mineral stabilizer 
are mixed in approximately equal proportions. The mineral stabilizer may consist of finely 
divided lime, silica, slate dust, dolomite, or other mineral materials. 

The weight of the fmished product is controlled by the amount of coating used. 
The coater rollers can be moved closer together to reduce the amount of coating applied to the 
felt, or separated to increase it. Many modem plants are equipped with automatic scales that 
weigh the sheets in the process of manufacture and warn the coater operator when the product 
is running under or over specifications. The coater is a significant emissions source within the 
roofmg production process. It releases asphalt fumes containing organics, some of which may 
be benzene compounds. 186,187 

The function of the coater-mixer is to mix coating asphalt and a mineral 
stabilizer in approximately equal proportions. The stabilized asphalt is then piped to the 
coating pan. The asphalt is piped in at about 450 to 500°F (232 to 260°C), and the mineral 
stabilizer is delivered by screw conveyor. There is often a preheater immediately ahead of the 


6-124 


coater-mixer to dry and preheat the material before it is fed into the coater-mixer. This 
eliminates moisture problems and also helps to maintain the temperature above 320 °F (160°C) 
in the coater-mixer. The coater-mixer is usually covered or enclosed, with an exhaust pipe for 
the air displaced by (or carried with) the incoming materials: The coater-mixer is viewed as a 
potential source of benzene emissions, but not a significant one. 186,187 

The next step in the production of coated roofing products is the application of 
mineral surfacing. The surfacing section of the roofing line usually consists of a 
multi-compartmented granule hopper, two parting agent hoppers, and two large press rollers. 
The hoppers are fed through flexible hoses from one or more machine bins above the line. 
These machine bins provide temporary storage and are sometimes called surge bins. The 
granule hopper drops colored granules from its various compartments onto the top surface of 
the moving sheet of coated felt in the sequence necessary to produce the desired color pattern 
on the roofing. This step is not required for smooth-surfaced products. 186 

Parting agents such as talc and sand (or some combination thereof) are applied 
to the top and back surfaces of the coated sheet from parting agent hoppers. These hoppers are 
usually of an open-top, slot-type design, slightly longer than the coated sheet is wide, with a 
screw arrangement for distributing the parting agent uniformly throughout its length. The first 
hopper is positioned between the granule hopper and the first large press roller, and 8 to 
12 inches (0.2 to 0.3 m) above the sheet. It drops a generous amount of parting agent onto the 
top surface of the coated sheet and slightly over each edge. Collectors are often placed at the 
edges of the sheet to pick up this overspray, which is then recycled to the parting agent 
machine bin by open screw conveyor and bucket elevator. The second parting agent hopper is 
located between the rollers and dusts the back side of the coated sheet. Because of the steep 
angle of the sheet at this point, the average fall distance from the hopper to the sheet is usually 
somewhat greater than on the top side, and more of the material falls off the sheet. 186 

In a second technique used to apply backing agent to the back side of a coated 
sheet, a hinged trough holds the backing material against the coated sheet and only material 


6-125 


that will adhere to the sheet is picked up. When the roofing line is not operating, the trough is 
tipped back so that no parting agent will escape past its lower lip. 

Immediately after application of the surfacing material, the sheet passes through 
the cool-down section. Here the sheet is cooled rapidly by passing it around water-cooled 
rollers in an abbreviated looper arrangement. Usually, water is also sprayed on the surfaces of 
the sheet to speed the cooling process. The cool-down section is not a source of benzene 
emissions. 


Following cooling, self-sealing coated sheets usually have an asphalt seal-down 
strip applied. The strip is applied by a roller, which is partially submerged in a pan of hot 
sealant asphalt. The pan is typically covered to minimize fugitive emissions. No seal-down 
strip is applied to standard shingle or roll-goods products. Some products are also texturized 
at this point by passing the sheet over an embossing roll that imparts a pattern to the surface of 

,1 _ , _ » -l '186 

uic coaicu sneci. 

The cooling process for both asphalt felt and coated sheets is completed in the 
next processing station, known as the finish looper. In the finish looper, sheets are allowed to 
cool and dry gradually. Secondly, the finish looper provides line storage to match the 
continuous operation of the line to the intermittent operation of the roll winder. It also allows 
time for quick repairs or adjustments to the shingle cutter and stacker during continuous line 
operation or, conversely, allows cutting and packaging to continue when the line is down for 
repair. Usually, this part of the process is enclosed to keep the fmal cooling process from 
progressing too rapidly. Sometimes, in cold weather, heated air is also used to retard cooling. 
The finish looper is not viewed as a source of benzene emissions. 186 

Following finishing, asphalt felt to be used in roll goods is wound on a mandrel, 
cut to the proper length, and packaged. When shingles are being made, the material from the 
finish looper is fed into the shingle-cutting machine. After the shingles have been cut, they are 


6-126 


moved by roller conveyor to manual or automatic packaging equipment. They are then stacked 
on pallets and transferred by forklift to storage areas or waiting trucks. 186 

6.12.2 Benzene Emissions from Asphalt Roofing Manufacture 

The primary benzene emission sources associated with asphalt roofing are the 
asphalt air-blowing stills (and associated oil knockout boxes) and the felt saturators. 186 An 
emission factor for benzene emissions from the blowing stills or saturators is given in 
Table 6-36. 189 Additional potential benzene emission sources may include the wet looper, the 
coater-mixer, the felt coater, the seal-down stripper, and air-blown asphalt storage tanks. 

Minor fugitive emissions are also possible from asphalt flux and blown asphalt handling and 
transfer operations. 186 ’ 188,190 

Process selection and control of process parameters have been promoted to 
minimize uncontrolled emissions, including oenzene, rrom asphalt air-blowing stills, asphalt 
saturators, wet loopers, and coaters. Process controls include the use of: 184 

• Dip saturators, rather than spray or spray-dip saturators; 

• Vertical stills, rather than horizontal stills; 

• Asphalts that inherently produce low emissions; 

• Higher-flash-point asphalts; 

• Reduced temperatures in the asphalt saturant pan; 

• Reduced asphalt storage temperatures; and 

• Lower asphalt-blowing temperatures. 

Dip saturators have been installed for most new asphalt roofing line installations 
in recent years, and this trend is expected to continue. Recent asphalt blowing still 
installations have been almost exclusively of the vertical type because of its higher efficiency 
and lower emissions. Vertical stills occupy less space and require no heating during oxidizing 


6-127 






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(if the temperature of the incoming flux is above 400 °F [204 °C]). Vertical stills are expected 
to be used in new installations equipped with stills and in most retrofit situations. 186 

Asphalt fluxes with lower flash points and softening points tend to have higher 
emissions of organics because these fluxes generally have been less severely cracked and 
contain more low-boiling fractions. Many of these light ends can be emitted during blowing. 
Limiting the minimum softening and flash points of asphalt flux should reduce the amount of 
benzene-containing fumes generated during blowing because less blowing is required to 
produce a saturant or coating asphalt. Saturant and coating asphalts with high softening points 
should reduce benzene emissions from felt saturation and coating operations. However, 
producing the higher softening point asphalt flux requires more blowing, which increases 
uncontrolled emissions from the blowing operation . 186 

Although these process-oriented emissions control measures are useful, 
emissions capture equipment and add-on emissions control equipment are also necessary in 
asphalt roofing material production facilities. The capture of potential benzene emissions from 
asphalt blowing stills, asphalt storage tanks, asphalt tank truck unloading, and the coater-mixer 
can and is being achieved in the industry by the use of enclosure systems around the 
emissions-producing operations. The enclosures are maintained under negative pressure, and 
the contained emissions are ducted to control devices . 186 Potential emissions from the 
saturator, wet looper, and coater are generally collected by a single enclosure by a canopy type 
hood or an enclosure/hood combination. 

No regulations were identified to control benzene emissions from hot-mix 

asphalt plants. 

6.13 CONSUMER PRODUCTS/BUILDING SUPPLIES 

This section covers benzene emissions from the application and use of consumer 
products rather than from the manufacture of such products. Because the types of consumer 


6-129 


products to which benzene emissions are attributed are so extensive, no list of manufacturers is 
presented here. 

Benzene emissions from the use of consumer products and building supplies 
have been reported in the literature. One indoor air quality data base for organic compounds, 
shows that indoor benzene levels have been measured in residences, commercial buildings, 
hospitals, schools, and office buildings. Substantiated sources of these benzene emissions were 
attributed to tobacco smoke, adhesives (including epoxy resins and latex caulks), spot cleaners, 
paint removers, particle board, foam insulation, inks, photo film, auto exhaust, and wood 
stain. 191,192 Although benzene emissions were detected from these consumer sources, no 
specific benzene emission factors were identified. In addition to these consumer sources, 
detergents have been identified as another possible source of benzene emissions. 191 

In another report, aromatic hydrocarbons (most likely including benzene) were 
listed as a constituent in certain automotive detailing and cleaning products, including 
body-cleaning compounds and engine cleaners/degreasers/parts cleaners. However, no 
specific emission levels were given. 192 

Naphtha (CAS number 8030-30-6) is a mixture of a small percentage of 
benzene, toluene, xylene, and higher homologs derived from coal tar by fractional distillation. 
Among its applications, naphtha is used as thinner in paints and varnishes and as a solvent in 
rubber cement. 106 Because naphtha contains a small percentage of benzene, some benzene 
emissions would be expected from these products. However, no qualifiable benzene emissions 
from naphtha-containing products were identified. 

The main control for reducing benzene emissions from consumer products is 
reformulation, such as substituting water or lower-VOC-emitting alternatives. 192 


6-130 



The federal government and several states are currently working on regulations 
for the benzene (or VOC) content of consumer products. Consumer products is a very diverse 
category and the products are used in a variety of applications. 193 


% 


6-131 




















































t it* » * 




























SECTION 7.0 

EMISSIONS FROM COMBUSTION SOURCES 


The following stationary point and area combustion source categories have been 
identified as sources of benzene emissions: medical waste incinerators (MWIs), sewage sludge 
incinerators (SSIs), hazardous waste incinerators, external combustion sources (e.g., utility 
boilers, industrial boilers, and residential stoves and furnaces), internal combustion sources, 
secondary lead smelters, iron and steel foundries, portland cement kilns, hot-mix asphalt 
plants, and open burning (of biomass, tires, and agricultural plastic). For each combustion 
source category, the following information is provided in the sections below: (1) a brief 
characterization of the U.S. population, (2) the process description, (3) benzene emissions 
characteristics, and (4) control technologies and techniques for reducing benzene emissions. In 
some cases, the current Federal regulations applicable to the source category are discussed. 


7.1 MEDICAL WASTE INCINERATORS 

MWIs bum wastes produced by hospitals, veterinary facilities, crematories, and 
medical research facilities. These wastes include both infectious (“red bag” and pathological) 
medical wastes and non-infectious, general housekeeping wastes. The primary purposes of 
MWIs are to (1) render the waste innocuous, (2) reduce the volume and mass of the waste, and 
(3) provide waste-to-energy conversion. The total number and capacity of MWIs in the United 
States is unknown; however, it is estimated that 90 percent of the 6,872 hospitals (where the 
majority of MWIs are located) in the nation have some type of on-site incinerator, if only a 
small unit for incinerating special or pathological waste. 194 The document entitled Locating 
and Estimating Air Toxic Emissions From Sources of Medical Waste Incinerators , contains a 


7-1 


more detailed characterization of the MWI industry, including a partial list of the U.S. MWI 
population. 


Three main types of incinerators are used for medical waste incineration: 
controlled-air, excess-air, and rotary kiln. Of the incinerators identified, the majority 
(> 95 percent) are controlled-air units. A small percentage (<2 percent) are excess-air. Less 
than 1 percent were identified as rotary kiln. The rotary kiln units tend to be larger, and 
typically are equipped with air pollution control devices. Approximately 2 percent of the total 
population identified were found to be equipped with air pollution control devices. 195 

7.1.1 Process Description: Medical Waste Incinerators 195 

Controlled-Air Incinerators 

Controlled-air incineration is the most widely used MWI technology and it now 

dominates the market for new systems at hospitals and similar medical facilities. This 
technology is also known as starved-air incineration, two-stage incineration, and modular 
combustion. Figure 7-1 presents a schematic diagram of a typical controlled-air unit. 195 

Combustion of waste in controlled-air incinerators occurs in two stages. In the 
first stage, waste is fed into the primary, or lower, combustion chamber, which is operated 
with less than the stoichiometric amount of air required for combustion. Combustion air enters 
the primary chamber from beneath the incinerator hearth (below the burning bed of waste). 

This air is called primary or underfire air. In the primary (starved-air) chamber, the low air- 
to-fuel ratio dries and facilitates volatilization of the waste, and most of the residual carbon in 
the ash bums. At these conditions, combustion gas temperatures are relatively low (1,400 to 
1,800°F [760 to 980 °C]). 

In the second stage, excess air is added to the volatile gases formed in the 
primary chamber to complete combustion. Secondary chamber temperatures are higher than 


7-2 



Carbon Dioxide, 

— Water Vapor 
and Excess 
Oxygen and Nitrogen 
to Atmosphere 


Main Burner for 
Minimum Combustion 
Temperature 


Volatile Content 
is Burned in 
Upper Chamber 

Excess Air 

Condition 


Starved-Air 
Condition in 
Lower Chamber 


Controlled 
Underfire Air 
for Burning 
Down Waste 



Figure 7-1. Controlled-Air Incinerator 


Source: Reference 195. 


7-3 










































































































































primary chamber temperatures—typically 1,800 to 2,000°F (980 to 1,095°C). Depending on 
the heating value and moisture content of the waste, additional heat may be needed. This can 
be provided by auxiliary burners located at the entrance to the secondary (upper) chamber to 
maintain desired temperatures. 

l 

Waste feed capacities for controlled-air incinerators range from about 75 to 
6,500 lb/hour (0.6 to 50 kg/min) (at an assumed fuel heating value of 8,500 Btu/lb 
[19,700 kJ/kg]). Waste feed and ash removal can be manual or automatic, depending on the 
unit size and options purchased. Throughput capacities for lower heating value wastes may be 
higher because feed capacities are limited by primary chamber heat release rates. Heat release 
rates for controlled-air incinerators typically range from 15,000 to 25,000 Btu/hr-ft 3 
(430,000 to 710,000 kJ/hr-m 3 ). 

Because of the low air addition rates in the primary chamber and corresponding 

lovv Hue gab velocities (and turbulence), the amount of solids entrained in the gases leaving the 

primary chamber is low. Therefore, the majority of controlled-air incinerators do not have 
add-on gas cleaning devices. 

Excess-Air Incinerators 

Excess-air incinerators are typically small modular units. They are also referred 
to as batch incinerators, multiple-chamber incinerators, and “retort” incinerators. Excess-air 
incinerators are typically a compact cube with a series of internal chambers and baffles. 
Although they can be operated continuously, they are usually operated in a batch mode. 

Figure 7-2 presents a schematic for an excess-air unit. 195 Typically, waste is 
manually fed into the combustion chamber. The charging door is then closed and an 
afterburner is ignited to bring the secondary chamber to a target temperature (typically 1,600 
to 1,800°F [870 to 980°C]). When the target temperature is reached, the primary chamber 
burner ignites. The waste is dried, ignited, and combusted by heat provided by the primary 


7-4 



Flame Port 


Stack 



Side View 



Figure 7-2. Excess-Air Incinerator 


Source: Reference 195. 


7-5 


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chamber burner, as well as by radiant heat from the chamber walls. Moisture and volatile 
components in the waste are vaporized and pass (along with combustion gases) out of the 
primary chamber and through a flame port that connects the primary chamber to the secondary 
or mixing chamber. 

Secondary air is added through the flame port and is mixed with the volatile 
components in the secondary chamber. Burners are also installed in the secondary chamber to 
maintain adequate temperatures for combustion of volatile gases. Gases exiting the secondarv 
chamber are directed to the incinerator stack or to a control device. When the waste is 
consumed, the primary burner shuts off. Typically, the afterburner shuts off after a set time. 
After the chamber cools, ash is manually removed from the primary chamber floor and a new 
charge of waste can be added. 

Incinerators designed to bum general hospital waste operate at excess air levels 
of up to 300 percent. If only pathological wastes are combusted, excess air levels near 
100 percent are more common. The lower excess air helps maintain higher chamber 
temperature when burning high-moisture waste. Waste feed capacities for excess-air 
incinerators are usually 500 lb/hr (3.8 kg/min) or less. 

Rotary Kiln Incinerators 

Rotary kiln incinerators, like the other types, are designed with a primary 
chamber where the waste is heated and volatilized and a secondary chamber where combustion 
of the volatile fraction is completed. The primary chamber consists of a slightly inclined, 
rotating kiln in which waste materials migrate from the feed end to the ash discharge end. The 
waste throughput rate is controlled by adjusting the rate of kiln rotation and the angle of 
inclination. Combustion air enters the primary chamber through a port. An auxiliary burner 
is generally used to start combustion and maintain desired combustion temperatures. Both the 
primary and secondary chambers are usually lined with acid-resistant refractory brick. Refer 
to Figure 7-9 of this chapter for a schematic diagram of a typical rotary kiln incinerator. In 


7-6 


Figure 7-9, the piece of equipment referred to as the “afterburner” is the equivalent of the 
“secondary chamber” referred to in this section. 

Volatiles and combustion gases pass from the primary chamber to the secondary 
chamber. The secondary chamber operates at excess air. Combustion of the volatiles is 
completed in the secondary chamber. Because of the turbulent motion of the waste in the 
primary chamber, solids burnout rates and particulate entrainment in the flue gas are higher for 
rotary kiln incinerators than for other incinerator designs. As a result, rotary kiln incinerators 
generally have add-on gas cleaning devices. 


7.1.2 Benzene Emissions From Medical Waste Incinerators 

There is limited information currently available on benzene emissions from 
MWIs. One emission factor for benzene emissions is provided in Table 7-1. 196 This factor 

represent: benzene emissions during combustion of both general hospital wastes and 
pathological wastes. 

7.1.3 Control Technologies for Medical Waste Incinerators 


Most control of air emissions of organic compounds is achieved by promoting 
complete combustion by following good combustion practice (GCP). In general, the 
conditions of GCP are as follows: 194 


Uniform wastefeed; 


• Adequate supply and good air distribution in the incinerator; 


Sufficiently high incinerator gas temperatures (> 1,500°F [>815°C]); 

Good mixing of combustion gas and air in all zones; 

Minimization of PM entrainment into the flue gas leaving the incinerator; 
and 


7-7 






TABLE 7-1 EMISSION FACTOR FOR MEDICAL WASTE INCINERATION 




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• Temperature control of the gas entering the air pollution control device 
to 450 °F (230°C) or less. 

Failure to achieve complete combustion of organic materials evolved from the 
waste can result in emissions of a variety of organic compounds. The products of incomplete 
combustion (PICs) range from low-molecular-weight hydrocarbons (e.g., methane, ethane, or 
benzene) to high-molecular-weight organic compounds (e.g., dioxins/furans). In general, 
adequate oxygen, temperature, residence time, and turbulence will minimize emissions of most 
organics. 


Control of organics may be partially achieved by using acid gas and PM control 
devices. To date, most MWIs have operated without add-on air pollution control devices. A 
small percentage (approximately 2 percent) of MWIs do use air pollution control devices, most 
frequently wet scrubbers and fabric filters. Fabric filters provide mainly PM control. Other 
PM control technologies include venturi scrubbers and electrostatic precipitators (ESPs). In 
addition to wet scrubbing, dry sorbent injection and spray dryer absorbers have also been used 
for acid gas (i.e., hydrogen chloride [HC1] and sulfur dioxide [S0 2 ]) control. Because it is not 
documented that acid gas/PM control devices provide reduction in benzene emissions from 
MWIs, further discussion of these types of control devices is not provided in this section. 
Locating and Estimating Air Toxic Emissions From Sources of Medical Waste Incinerators , 194 
contains a more detailed description of the acid gas/PM air pollution control devices utilized 
for MWIs, including schematic diagrams. 

7.1.4 Re gulatory Analysis 

Air emissions from MWIs are not currently regulated by Federal standards. 
However, Section 129 of the CAA requires that standards be established for new and existing 
MWIs. Standards for MWIs were proposed under Section 129 of the CAA on 
February 27, 1995 (38 FR 10654). Section 129 requires that the standards include emission 
limits for HC1, SO : , and CO, among other pollutants. Section 129 also specifies that the 
standards may require monitoring of surrogate parameters (e.g., flue gas temperature). Thus, 


7-9 



the standards may require GCP, which would likely result in benzene emissions reduction. 
Additionally, the standards may require acid gas/PM control device requirements, which may 
result in some benzene emissions reduction. 

7.2 SEWAGE SLUDGE INCINERATORS 

There are approximately 170 sewage sludge incineration (SSI) plants operating 
in ihe United Suica. The three main types of SSIs are: multiple-hearth furnaces (MHF). 
fluidized-bed combustors (FBC), and electric infrared incinerators. Some sludge is co-fired 
with municipal solid waste in combustors, based on refuse combustion technology. Refuse 
co-fired with sludge in combustors based on sludge incinerating technology is limited to MHFs 
only. 197 

Over 80 percent of the identified operating sludge incinerators are of the 
multiple-hearth design. About 15 percent are FBCs and 3 percent are electric infrared 
incinerators. The remaining combustors co-fire refuse with sludge. Most sludge incinerators 
are located in the Eastern United States, although there are a significant number on the West 
Coast. New York has the largest number of facilities, with 33. Pennsylvania and Michigan 
have the next largest number of facilities, with 21 and 19 sites, respectively. 197,198 Locating 
and Estimating Air Toxics Emissions for Sewage Sludge Incinerators contains a diagram 
showing the geographic distribution of the existing population. 198 

The three main types of sewage sludge incinerators are described in the 
following sections. Single hearth cyclone, rotary kiln, wet air oxidation, and co-incineration 
are also briefly discussed. 


7-10 


7.2.1 


Process Description: Sewage Sludge Incinerators 197 ’ 198 


Multiple-Hearth Furnaces 

A cross-sectional diagram of a typical MHF is shown in Figure 7-3. 198 The 
basic MHF is a vertically oriented cylinder. The outer shell is constructed of steel, lined with 
refractory, and surrounds a series of horizontal refractory hearths. A hollow cast-iron rotating 
shaft runs through the center of the hearths. Cooling air is introduced into the shaft, which 
extend above the hearths. Attached to the central shaft are the rabble arms, which extend 
above the hearths. Each rabble arm is equipped with a number of teeth approximately 6 inches 
in length and spaced about 10 inches apart. The teeth are shaped to rake the sludge in a spiral 
motion, alternating in direction from the outside in to the inside out, between hearths. Burners 
are located in the sidewalls of the hearths to provide auxiliary heat. 

In most MKFs, partially dewatered sludge is fed onto the perimeter of the top 

hearth. The rabble arms move the sludge through the incinerator by raking the sludge toward 
the center shaft, where it drops through holes located at the center of the hearth. In the next 
hearth, the sludge is raked in the opposite direction. This process is repeated in all of the 
subsequent hearths. The effect of the rabble motion is to break up solid material to allow 
bener surface contact with heat and oxygen. A sludge depth of about 1 inch is maintained in 
each hearth at the design sludge flow rate. 

Scum may also be fed to one or more hearths of the incinerator. Scum is the 
material that floats on wastewater. It is generally composed of vegetable and mineral oils, 
grease, hair, waxes, fats, and other materials that will float. Scum may be removed from 
many treatment units, including pre-aeration tanks, skimming tanks, and sedimentation tanks. 
Quantities of scum are generally small compared to those of other wastewater solids. 

Ambient air is first ducted through the central shaft and its associated rabble 
arms. A portion or all of this air is then taken from the top of the shaft and recirculated into 


7-11 



COOLING AIR 
DISCHARGE 


SCUM 



AUXILIARY 
AIR PORTS 

RABBLE ARM 
2 OR 4 PER 
HEARTH 


BURNERS 

SUPPLEMENTAL 

FUEL 

COMBUSTION AIR 


SHAFT COOLING 

AIR RETURN 


SOLIDS FLOW 


DROP HOLES 


Figure 7-3. Cross Section of a Multiple Hearth Furnace 


Source: Reference 198. 


7-12 


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the lower-most hearth as preheated combustion air. Shaft cooling air that is not circulated back 
into the furnace is ducted into the stack downstream of the air pollution control devices. The 
combustion air flows upward through the drop holes in the hearths, countercurrent to the flow 
of the sludge, before being exhausted from the top hearth. Air enters the bottom to cool the 
ash. Provisions are usually made to inject ambient air directly into the middle hearths as well. 

i 

Overall, an MHF can be divided into three zones. The upper hearth comprises 
the drying znnp where most of the moisture in the sludge is evaporated. The temperature in 
the drying zone is typically between 800 and 1,400°F (425 and 760°C). Sludge combustion 
occurs in the middle hearth (second zone) as the temperature is increased to 1,100 to 1,700°F 
(600 to 930°C). The combustion zone can be further subdivided into the upper-middle hearth, 
where the volatile gases and solids are burned, and the lower-middle hearth, where most of the 
fixed carbon is combusted. The third zone, made up of the lower-most hearth, is the cooling 
zone. In this zone, the ash is cooled as its heat is transferred to the incoming combustion air. 

Under normal operating conditions. 50 to 100 percent excess air must be added 
to an MHF in order to ensure complete combustion of the sludge. Besides enhancing contact 
between fuel and oxygen in the furnace, these relatively high rates of excess air are necessary 
to compensate for normal variations in both the organic characteristics of the sludge feed and 
the rate at which it enters the incinerator. When the supply of excess air is inadequate, only 
partial oxidation of the carbon will occur, with a resultant increase in emissions of CO, soot, 
and hydrocarbons. Too much excess air, on the other hand, can cause increased entrainment 
of paniculate and unnecessarily high auxiliary fuel consumption. 

Fluidized-Bed Combustors 

Figure 7-4 shows a cross-sectional diagram of an FBC. 198 FBCs consist of a 
vertically oriented outer shell constructed of steel and lined with refractory. Tuyeres (nozzles 
designed to deliver blasts of air) are located at the base of the furnace within a refractory-lined 
grid. A bed of sand, approximately 2.5 feet (0.75 meters) thick, rests upon the grid. Two 


7-13 


■ Exhaust and Ash 



Figure 7-4. Cross Section of a Fluidized Bed Furnace 


Source: Reference 198. 


7-14 












































































































































general configurations can be distinguished on the basis of how the fluidizing air is injected 
into the furnace. In the “hot windbox” design, the combustion air is first preheated by passing 
through a heat exchanger, where heat is recovered from the hot flue gases. Alternatively, 
ambient air can be injected directly into the furnace from a cold windbox. 


Partially dewatered sludge is fed into the lower portion of the furnace. Air 
injected through the tuyeres at a pressure of 3 to 5 pounds per square inch gauge (20 to 
35 kilopascals), simultaneously fluidizes the bed of hot sand and the incoming sludge. 
Temperatures of 1,400 to 1,700°F (750 to 925°C) are maintained in the bed. As the sludge 
bums, fine ash particles are carried out the top of the furnace. Some sand is also removed in 
the air stream and must be replaced at regular intervals. 



Combustion of the sludge occurs in two zones. Within the sand bed itself (the 
fust zone), evaporation of the water and pyrolysis of the organic materials occur nearly 
simultaneously as the temperature of the sludge is rapidly raised In the freeboard area (the 
second zone), the remaining free carbon and combustible gases are burned. The second zone 
functions essentially as an afterburner. 

Fluidization achieves nearly ideal mixing between the sludge and the combustion 
air, and the turbulence facilitates the transfer of heat from the hot sand to the sludge. The 

most noticeable impact of the better burning atmosphere provided by an FBC is seen in the 
limited amount of excess air required for complete combustion of the sludge. Typically, FBCs 
can achieve complete combustion with 20 to 50 percent excess air, about half the excess air 
required by MHFs. As a consequence, FBCs generally have lower fuel requirements 
compared to MHFs. 


Electric Infrared Incinerators 


Electric infrared incinerators consist of a horizontally oriented, insulated 

furnace. A woven wire belt conveyor extends the length of the furnace and infrared heating 


7-15 


elements are located in the roof above the conveyor belt. Combustion air is preheated by the 
flue gases and is injected into the discharge end of the furnace. Electric infrared incinerators 
consist of a number of prefabricated modules that can be linked together to provide the 
necessary furnace length. A cross-section of an electric furnace is shown in Figure 7-5. 198 

The dewatered sludge cake is conveyed into one end of the incinerator. An 
internal roller mechanism levels the sludge into a continuous layer approximately 1 inch thick 
across the width of the belt. The sludge is sequentially dried and then burned as it moves 
beneath the infrared heating elements. Ash is discharged into a hopper at the opposite end of 
the furnace. The preheated combustion air enters the furnace above the ash hopper and is 
further heated by the outgoing ash. The direction of air flow is countercurrent to the 
movement of the sludge along the conveyor. Exhaust gases leave the furnace at the feed end. 
Excess air rates vary from 20 to 70 percent. 

Other Technologies 

A number of other technologies have been used for incineration of sewage 
sludge, including cyclonic reactors, rotary kilns, and wet oxidation reactors. These processes 
are not in widespread use in the United States and are discussed only briefly. 

The cyclonic reactor is designed for small-capacity applications and consists of a 
vertical cylindrical chamber that is lined with refractory. Preheated combustion air is 
introduced into the chamber tangentially at high velocities. The sludge is sprayed radially 
toward the hot refractory walls. Combustion is rapid, such that the residence time of the 
sludge in the chamber is on the order of 10 seconds. The ash is removed with the flue gases. 

Rotary kilns are also generally used for small capacity applications. The kiln is 
inclined slightly from the horizontal plane, with the upper end receiving both the sludge feed 
and the combustion air. A burner is located at the lower end of the kiln. The circumference of 


7-16 


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7-17 


"igure 7-5. Cross Section of an I Electric Infrared Furnace 














































the kiln rotates at a speed of about 6 inches per second. Ash is deposited into a hopper located 
below the burner. 

The wet oxidation process is not strictly one of incineration; it instead utilizes 
oxidation at elevated temperature and pressure in the presence of water (flameless combustion). 
Thickened sludge, at about 6-percent solids, is first ground and mixed with a stoichiometric 
amount of compressed air. The sludge/air mixture is then circulated through a series of heat 
exchangers before entering a pressurized reactor. The temperature of the reactor is held 
between 350 and 600°F (175 and 315°C). The pressure is normally 1,000 to 1,800 pounds 
per square inch grade (7,000 to 12,500 kilopascals). Steam is usually used for auxiliary heat. 
The water and resulting ash are circulated out the reactor and are separated in a tank or lagoon. 
The liquid phase is recycled to the treatment plant. Off-gases must be treated to eliminate 
odors. 

Co-Incineration and Co-Firing 

Wastewater treatment plant sludge generally has a high water content and, in 
some cases, fairly high levels of inert materials. As a result, the net fuel value of sludge is 
often low. If sludge is combined with other combustible materials in a co-incineration scheme, 
a furnace feed can be created that has both a low water concentration and a heat value high 
enough to sustain combustion with little or no supplemental fuel. Virtually any material that 
can be burned can be combined with sludge in a co-incineration process. Common materials 
for co-incineration are coal, municipal solid waste (MSW), wood waste, and agricultural 
waste. 


There are two basic approaches to combusting sludge with MSW: (1) use of 
MSW combustion technology by adding dewatered or dried sludge to the MSW combustion 
unit, and (2) use of sludge combustion technology by adding processed MSW as a 
supplemental fuel to the sludge furnace. With the latter, MSW is processed by removing 
noncombustibles, shredding, air classifying, and screening. Waste that is more finely 


7-18 


processed is less likely to cause problems such as severe erosion of the hearths, poor 
temperature control, and refractory failures. 


7,2.2 


Benzene Emissions from Sewage Sludge Incineration 


Emission factors associated with MHFs and FBCs are provided in Table 7-2. 197 
This table provides a comparison of benzene emissions based on no control and control with 
various PM control devices and an afterburner. However, these emission factors do not reflect 
the effect of increased operating temperature on reducing benzene emissions. As discussed in 
Section 7.2.3, increasing the combustion temperature facilitates more complete combustion of 
organics, resulting in lower benzene emissions. It was not possible in this study to compare 
the combustor operating conditions of all SSIs for which emissions test data were available to 
develop the emission factors in Table 7-2. 197 As a result, it was not possible to reflect the 
effect of combustion temperature on benzene emissions. The emission factors for MHFs 


•» • nr i — 

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arc based on test data of combustors operated at a variety of combustion 


temperatures in the primary combustion hearths (1,100 to 1,700°F [600 to 930°C]). 


Using emissions test data for one sewage sludge combustion facility, it was 
possible to demonstrate the benzene emission reduction achieved with the practice of increasing 
operating temperature versus utilizing an afterburner or a scrubber. This comparison is 
provided m Table 7-3. 199 The emissions test data for the one facility used to develop the 
emission factors presented in Table 7-3 are also averaged into the emission factors presented in 
Table 7-2. 


7.2.3 Control Technologies for Sewage Sludge Incinerators 197 - 198 

Control of benzene emissions from SSIs is achieved primarily by promoting 
complete combustion by following GCP. The general conditions of GCP are summarized in 
Section 7.1.3. As with MWIs, failure to achieve complete combustion of organic materials 
evolved from the waste can result in emissions of a variety of organic compounds, including 


7-19 





TABLE 7-2. SUMMARY OF EMISSION FACTORS FOR SEWAGE SLUDGE NCINERATION 


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7-20 


MHF = multiple hearth furnace. 
FBC = fluidized bed combustor. 




















TABLE 7-3. SUMMARY OF EMISSION FACTORS I OR ONE SEWAGE SLUDGE INCINERATION 

FACILITY UTILIZING A MULTIPLE HEARTH FURNACE 


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benzene, and adequate oxygen, temperature, residence time, and turbulence will generally 
minimiz e emissions of most organics. 

Many SSIs have greater variability in their organic emissions than do other 
waste incinerators because, on average, sewage sludge has a high moisture content and the 
moisture content can vary widely during operation. 200 

Additional reductions in benzene emissions may be achieved by utilizing PM 
control devices; however, it is not always the case that a PM control device will reduce 
benzene emissions. In some cases, the incinerator operating conditions (e.g., combustion 
temperature and temperature at the air pollution control device) may affect the performance of 
scrubbers. 199 The types of existing SSI PM controls range from low-pressure-drop spray 
towers and wet cyclones to higher-pressure-drop venturi scrubbers and venturi/impingement 
tray scrubber combinations. A few ESPs and baghouses are employed, primarily where sludge 
is co-iired wiui MSW. 

The most widely used PM control device applied to an MHF is the impingement 
tray scrubber. Older units use the tray scrubber alone and combination venturi/impingement 
tray scrubbers are widely applied to newer MHFs and some FBCs. Most electric incinerators 
and some FBCs use venturi scrubbers only. As indicated in Table 7-3, venturi/impingement 
tray scrubbers have been demonstrated to reduce benzene emissions from SSIs. 

A schematic diagram of a typical combination venturi/impingement tray 
scrubber is presented in Figure 7-6. 198 Hot gas exits the incinerator and enters the precooling 
or quench section of the scrubber. Spray nozzles in the quench section cool the incoming gas, 
and the quenched gas then enters the venturi section of the control device. 

Venturi water is usually pumped into an inlet weir above the quencher. The 
venturi water enters the scrubber above the throat, completely flooding the throat. Turbulence 
created by high gas velocity in the converging throat section deflects some of the water 


7-22 


Gas Exit to Induced Draft 
Fan and Stack 



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Figure 7-6. Venturi/Impingement Tray Scrubber 


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7-23 



































traveling down the throat into the gas stream. PM carried along with the gas stream impacts 
on these water particles and on the water wall. As the scrubber water and flue gas leave the 
venturi section, they pass into the flooded elbow, where the stream velocity decreases, 
allowing the water and gas to separate. By restricting the throat area within the venturi, the 
linear gas velocity is increased and the pressure drop is subsequently increased, increasing PM 
removal efficiency. 

At the base of the flooded elbow, the gas stream passes through a connecting 
duct to the base of the impingement tray tower. Gas velocity is further reduced upon entry to 
the tower as the gas stream passes upward through the perforated impingement trays. Water 
usually enters the trays from inlet ports on opposite sides and flows across the tray. As gas 
passes through each perforation in the tray, it creates a jet that bubbles up the water and further 
entrains solid particles. At the top of the tower is a mist eliminator to reduce the carryover of 
water droplets in the stack effluent gas. The impingement section can contain from one to four 
trays. 

In the case of MHFs, afterburners may be utilized to achieve additional 
reduction of organic emissions, including benzene. MHFs produce more benzene emissions 
because they are designed with countercurrent air flow. Because sludge is usually fed into the 
top of the furnace, hot air and wet sludge feed are contacted at the top of the furnace, such that 
any compounds distilled from the solids are immediately vented from the furnace at 
temperatures too low to completely destroy them. 

Utilization of an afterburner provides a second opportunity for these unbumed 
hydrocarbons to be fully combusted. In afterburning, furnace exhaust gases are ducted to a 
chamber, where they are mixed with supplemental fuel and air and completely combusted. 
Additionally, some incinerators have the flexibility to allow sludge to be fed to a lower hearth, 
thus allowing the upper hearth(s) to function essentially as an afterburner. 


7-24 


7.2.4 


Regulatory Analysis 


Prior to 1993, organic emissions from SSIs were not regulated. On 
February 19, 1993, Part 503 was added to Subchapter O in Chapter I of Title 40 of the CFR, 
establishing standards for use or disposal of sewage sludge. Subpart E of Part 503 regulates 
emissions of total hydrocarbons (THC) from the incineration of SSIs and applies to all SSIs. 
The THC limit of 100 ppm (measured as a monthly average) is a surrogate for all organic 
compounds, including benzene. In establishing a standard for organic emissions, EPA had 
considered establishing a standard for 14 individual organic compounds, including benzene; 
however, it was concluded that the individual organic pollutants were not significant enough a 
factor in sewage sludge to warrant requiring individual pollutant limits. Furthermore, based 
on a long-term demonstration of heated flame ionization detection systems monitoring organic 
emissions from SSIs, it was concluded that there is an excellent correlation between THC 
emission levels and organic pollutant emission levels. 

The THC limit established in Part 503 is an operational standard that would, in 
general, not require the addition of control devices to existing incinerators, but would require 
incinerators to adopt good operating practices on a continuous basis. It is expected that FBCs 
and MHFs will have no difficulty meeting the standard. 200 To ensure the adoption of GCP, the 
standard requires continuous THC monitoring using a flame ionization detection system, 
continuous monitoring of the moisture content in the exit gas, and continuous monitoring of 
combustion temperature. 

7.3 HAZARDOUS WASTE INCINERATION 

Hazardous waste is produced in the form of liquids (e.g., waste oils, 
halogenated and nonhalogenated solvents, other organic liquids, and pesticides/ herbicides) 
and sludges and solids (e.g., halogenated and nonhalogenated sludges and solids, dye and paint 
sludges, resins, and latex). Based on a 1986 study, total annual hazardous waste generation in 
the United States was approximately 292 million tons (265 million metric tons). 201 Only a 


7-25 



small fraction of the waste (< 1 percent) was incinerated. The major types of hazardous waste 
streams incinerated were spent nonhalogenated solvents and corrosive and reactive wastes 
contaminated with organics. Together, these accounted for 44 percent of the waste 
incinerated. Other prominent wastes included hydrocyanic acid, acrylonitrile bottoms, and 
nonlisted ignitable wastes. 

Hazardous waste can be thermally destroyed through burning under oxidative 
conditions in incineration systems designed specifically for this purpose and in various types of 
industrial kilns, boilers, and furnaces. The primary purpose of a hazardous waste incinerator 
is the destruction of the waste; some systems include energy recovery devices. An estimated 
1.9 million tons (1.7 million Mg) of hazardous waste were disposed of in incinerators in 
1981. 201 The primary purpose of industrial kilns, boilers, or furnaces is to produce a 
commercially viable product such as cement, lime, or steam. An estimated 230 million gallons 
of waste fuel and waste oil were treated at industrial kilns, boilers, and furnaces in 1983. 201 In 
1981. it was estimated that industrial kilns, boilers, and furnaces disposed of more than twice 
the amount of waste that was disposed of via incinerators. 201 

7.3.1 Process Description: Incineration 

Incineration is a process that employs thermal decomposition via thermal 
oxidation at high temperatures (usually 1,650°F [900°C] or greater) to destroy the organic 
fraction of the waste and reduce volume. A study conducted in 1986 identified 221 hazardous 
waste incinerators operating under the Resource Conservation and Recovery Act (RCRA) 
system in the United States. (See Section 7.3.5 for a discussion of this and other regulations 
applicable to hazardous waste incineration.) These incinerators are located at 189 separate 
facilities, 171 of which are located at the site of waste generation. 201 

A diagram of the typical process component options in a hazardous waste 
incineration facility is provided in Figure 7-7. 201 The diagram shows that the major subsystems 
that may be incorporated into the hazardous waste incineration system are (1) waste 


7-26 




Waste Preparation Combustion Air Pollution Control 




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7-27 


Figure 7-7. General Orientation of Hazardous Waste Incineration Subsystems and Typical Component Options 











































preparation and feeding, (2) combustion chamber(s), (3) air pollution control, and (4) 
residue/ash handling. These subsystems are discussed in this section, except that air pollution 
control devices are discussed in Section 7.3.4 of this section. 

Additionally, energy-recovery equipment may be installed as part of the 
hazardous waste incineration system, provided that the incinerator is large enough to make 
energy recovery economically productive (i.e., bigger than about 7 million Btu/hour 
[7.4 million kJ/hourl) and that corrosive constituents (e.g., HC1) and adhesive particulates are 
not present at levels that would damage the equipment. 202 

Additionally, a few other technologies have been used for incineration of 
hazardous waste, including ocean incineration vessels and mobile incinerators. These 
processes are not in widespread use in the United States and are discussed only briefly. 

Waste Preparation and Feeding^* 

The feed method is determined by the physical form of the hazardous waste. 
Waste liquids are blended and then pumped into the combustion chamber through nozzles or 
via atomizing burners. Liquid wastes containing suspended panicles may need to be screened 
to avoid clogging of small nozzle or atomizer openings. Liquid wastes may also be blended in 
order to control the heat content of the liquid to achieve sustained combustion (typically to 
8,000 Btu/lb [18,603 kJ/kg]) and to control the chlorine (CL) content of the waste fed to the 
incinerator (typically to 30 percent or less) to limit the potential for formation of 
hazardous-free Cl 2 gas in the combustion gas. 

Waste sludges are typically fed to the combustion chamber using progressive 
cavity pumps and water-cooled lances. Bulk solid wastes may be shredded to control particle 
size and may be fed to the combustion chamber via rams, gravity feed, air lock feeders, 
vibratory or screw feeders, or belt feeders. 


7-28 


Combustion Chambers 201,202 


today: 202 


The following five types of combustion chambers are available and operating 


• Liquid injection; 

• Rotary kiln; 

• Fixed-hearth: 

• Fluidized-bed; and 

• Fume. 

These five types of combustion chambers are discussed below. 

Liquid iniection --Liquid injection combustion chambers are applicable almost 
exclusively for pumpable liquid waste, including some low-viscosity sludges and slurries. The 
typical capacity of liquid injection units is about 8 to 28 million Btu/hour (8.4 to 29.5 million 
kJ/hr). Figure 7-8 presents a typical schematic diagram of a liquid-injection unit. 201 

Liquid injection units are usually simple, refractory-lined cylinders (either 
horizontally or vertically aligned) equipped with one or more waste burners. Vertically 
aligned units are preferred when wastes are high in organic salts and fusable ash content; 
horizontal units may be used with low-ash waste. Liquid wastes are injected through the 
bumer(s), atomized to fme droplets, and burned in suspension. Burners and separate waste 
injection nozzles may be oriented for axial, radial, or tangential firing. Good atomization, 
using gas-fluid nozzles with high-pressure air or steam or with mechanical (hydraulic) means, 
is necessary to achieve high liquid waste destruction efficiency. 

Rotary Kiln --Rotarv kiln incinerators are applicable to the destruction of solid 
wastes, slurries, containerized waste, and liquids. Because of their versatility, they are most 


7-29 




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7-30 


Figure 7-8. Typical Liquid Injection Combustion Chamber 





























frequently used by commercial off-site incineration facilities. The typical capacity of these 
units is about 10 to 60 million Btu/hour. Figure 7-9 presents a typical schematic diagram of a 
rotary kiln unit. 201 

Rotary kiln incinerators generally consist of two combustion chambers: a 
rotating kiln and an afterburner. The rotary kiln is a cylindrical refractory-lined shell that is 
mounted on a slight incline. The incline facilitates ash and slag removal. Rotation of the shell 
provides transportation of the waste through the kiln and enhances mixing of the waste with 
combustion air. The rotational speed of the kiln is used to control waste residence time and 
mixing. The primary function of the kiln is to convert solid wastes to gases, which occurs 
through a series of volatilization, destructive distillation, and partial combustion reactions. 

An afterburner is connected directly to the discharge end of the kiln. The 
afterburner is used to ensure complete combustion of flue gases before their treatment, for air 
pollutants. A ternary combustion chamber may be added if needed. The afterburner itself 
may be horizontally or vertically aligned, and functions much on the same principles as the 
liquid injection unit described above. Both the afterburner and the kiln are usually equipped 
with an auxiliary fuel-firing system to control the operating temperature. 

Fixed-Hearth --Fixed-hearth incinerators, also called controlled-air, starved-air, 
or pyrolytic incinerators, are the third major technology used for hazardous waste incineration. 
This type of incinerator may be used for the destruction of solid, sludge, and liquid wastes. 
Fixed-hearth units tend to be of smaller capacity (typically 5 million Btu/hr [5.3 million kJ/hr]) 
than liquid injection or rotary kiln incinerators because of physical limitations in ram-feeding 
and transporting large amounts of waste materials through the combustion chamber. Lower 
relative capital costs and reduced particulate control requirements make fixed-hearth units more 
attractive than rotary kilns for smaller on-site installations. Figure 7-10 presents a typical 
schematic diagram of a fixed-hearth unit. 201 


7-31 




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7-32 


Figure 7-9 Typical Rotary Kiln/Afterburner Combustion Chamber 








































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7-33 



















































































Fixed-hearth units consist of a two-stage combustion process similar to that of 
rotary kilns. Waste is ram-fed into the primary chamber and burned at about 50 to 80 percent 
of stoichiometric air requirements. This starved-air condition causes most of the volatile 
fraction to be destroyed pyrolitically. The resultant smoke and pyrolytic products pass to the 
secondary chamber, where additional air and, in some cases, supplemental fuel, are injected to 
complete the combustion. 

Fluidized-Bed —FBCs have only more recently been applied to hazardous waste 
incineration. FBCs may be applied to solids, liquids, and gases; however, this type of 
incinerator is most effective for processing heavy sludges and slurries. Solids generally 
require prescreening or crushing to a size less than 2 inches in diameter. The typical capacity 
of this type of incinerator is 45 million Btu/hr (47.5 million kJ/hr). See Figure 7-4 of this 
chapter for a typical schematic diagram of an FBC chamber. 

FBC chambers consist of a single refractory-lined combustion vessel partially 

filled with inert granular material (e.g., particles of sand, alumina, and sodium carbonate). 
Combustion air is supplied through a distributor plate at the base of the combustor at a rate 
sufficient to fluidize (bubbling bed) or entrain (circulating bed) the bed material. The bed is 
preheated to startup temperatures by a burner. The bed material is kept at temperatures 
ranging from 840 to 1,560°F (450 to 850°C). Wastes are injected into the combustion 
chamber pneumatically, mechanically, or by gravity. Solid wastes are fed into the combustion 
chamber through an opening above the fluidized bed (similar to the opening for sand feed, 
represented in Figure 7-4). Liquid wastes are fed into the bottom of the fluidized bed 
(represented in Figure 7-4 as the opening designated for sludge feed). As the waste is fed to 
the combustion chamber, heat is transferred from the bed material to the wastes. Upon 
combustion, the waste returns heat to the bed. The high temperature of the bed also allows for 
combustion of waste gases above the bed. 

Fume -Fume incinerators are used exclusively to destroy gaseous or fume 
wastes. The combustion chamber is comparable to that of a liquid-injection incinerator 


7-34 




(Figure 7-8) in that it usually has a single chamber, is vertically or horizontally aligned, and 
uses nozzles to inject the waste into the chamber for combustion. Waste gases are injected by 
pressure or atomization through the burner nozzles. Wastes may be combusted solely by 
thermal or catalytic oxidation. If no catalyst is used, the combustion chamber temperature is 
maintained at 1,200 to 1,800°F (650 to 980°C). If a catalyst is used (e.g., alumina coated 
with noble metals, such as platinum or palladium, and other metals, such as copper chromate 
or manganese), the temperature may be maintained at lower temperatures of 500 to 900°F 
(260 to 480 °C). 

Residue and Ash Handling 201 

Residue and ash consist of the inorganic components of the hazardous waste that 
are not destroyed by incineration. Bottom ash is created in the combustion chamber and 
residue collects in the air pollution control devices. After discharge from the combustion 
chambe r bottom commonly air-cooled or quenched with water. The ash is then 
accumulated on site in storage lagoons or in drums prior to disposal to a permitted hazardous 
waste land disposal facility. The ash may also be dewatered or chemically fixated/stabilized 
prior to disposal. 

Air pollution control residues are typically aqueous streams containing PM, 
absorbed acid gases, and small amounts of organic material. These streams are collected m 
sumps or recirculation tanks, where the acids are neutralized with caustic and returned to the 
process. When the total dissolved solids in the aqueous stream exceeds 3 percent, a portion of 
the wastes is discharged for treatment and disposal. 

Ocean Incinerators 

Ocean incineration involves the thermal destruction of liquid hazardous wastes 
at sea in specially designed tanker vessels outfitted with high-temperature incinerators. Ocean 
incinerators are identical to land-based liquid injection incinerators, except that current ocean 


7-35 


incinerators are not equipped with air pollution control systems. Largely due to public concern 
over potential environmental effects, ocean incineration of hazardous waste has not been used 
on a routine basis in the United States. 201 

Mobile Incinerators 

Mobile incinerators have been developed for on-site cleanup at uncontrolled 
hazardous waste sites. Most of these systems are scaled-down, trailer-mounted versions of a 
conventional rotary kiln or an FBC, with thermal capacities ranging from 10 to 20 million 
Btu/hr (10.5 to 21.1 million kJ/hr). The performance of these mobile systems has been shown 
to be comparable to equivalent stationary facilities. Because of their high cost, these types of 
systems are considered to be cost-effective only at waste sites where large amounts of 
contaminated material (e.g., soil) would need to be transported off site. 201 

7 3.2 Industrial Kilns Boilers, and Furnaces 


Industrial kilns, boilers, and furnaces bum hazardous wastes as fuel to produce 
commercially viable products such as cement, lime, iron, asphalt, or steam. These industrial 
sources require large inputs of fuel to produce the desired product. Hazardous waste, which is 
considered an economical alternative to fossil fuels for energy and heat, is utilized as a 
supplemental fuel. In the process of producing energy and heat, the hazardous wastes are 
subjected to high temperature for a sufficient time to destroy the hazardous content and the 
bulk of the waste. 

Based on a study conducted in 1984, there were over 1,300 facilities using 
hazardous waste-derived fuels (HWDF) in 1983, accounting for a total of 230 million gallons 
(871 million liters) of waste fuel and waste oil per year. Although the majority (69 percent) of 
HWDF is burned by only about 2 percent of the 1,300 facilities (i.e., medium- to large-size 
industrial boilers, cement and aggregate kilns, and iron-making furnaces), other industries 
burning significant quantities of HWDF included the paper (SIC 26), petroleum (SIC 29), 


7-36 



primary metals (SIC 33), and stone, clay, glass, and concrete (SIC 32) industries. 201 Industrial 
boilers and furnaces, iron foundries, and cement kilns are described in more detail in 
Sections 7.4, 7.7, and 7.8, respectively, of this document. 

7.3.3 Benzene Emissions From Hazardous Waste Incineration 

There are limited data documenting benzene emissions from hazardous waste 
incinerators. However, as discussed below, benzene is one of the most frequently identified 
products of incomplete combustion (PICs) in air emissions from hazardous waste 
incinerators. 203 Two emission factors for benzene emissions are provided in Table 7-4. 

7.3.4 Control Technologies for Hazardous Waste Incineration 

Most organics control is achieved by promoting complete combustion by 
following GCP The general condition* of GCP are summarized in Section 7.1.3. Again, 
failure to achieve complete combustion of organic materials evolved from the waste can result 
in emissions of a variety of organic compounds. Benzene is one of the most frequently 
identified PICs in air emissions from hazardous waste incinerators. 203 

In addition to adequate oxygen, temperature, residence time, and turbulence, 
control of organics may be partially achieved by using acid gas and PM control devices; 
however, this has not been documented. The most frequently used control devices for acid gas 
and PM control are wet scrubbers and fabric filters. Fabric filters provide mainly PM control. 
Other PM control technologies include venturi scrubbers and ESPs. In addition to wet 
scrubbing, dry sorbent injection and spray dryer absorbers have also been used for acid gas 
(HC1 and S0 2 ) control. 


7-37 






TABLE 7-4. SUMMARY OF BENZENE EMISSION FACTOI S 
FOR HAZARDOUS WASTE INCINERATION 


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7.3.5 


Regulatory Analysis 


Organic emissions from hazardous waste incinerators are regulated under 
40 CFR 246, Subpart O, promulgated on June 24, 1982. 204 The standards require that in order 
for a hazardous waste incineration facility to receive a RCRA permit, it must attain a 99.99 
percent destruction and removal efficiency (DRE) for each principal organic hazardous 
constituent (POHC) in the waste feed. Each facility must determine which one or more 
organic compounds, from a list of approximately 400 organic and inorganic hazardous 
chemicals (including benzene) in Appendix VIII of 40 CFR 261, 205 are POHCs, based on 
which are the most difficult to incinerate, considering their concentration or mass in the waste 
feed. Each facility must then conduct trial bums to determine the specific operating conditions 
under which 99.99 percent DRE is achieved for each POHC. 

In order to ensure 99.99 percent DRE, operating limits are established in a 
permit for each incinera tnr fo r the following conditions* (1) CO level in the stack exhaust gas. 
(2) waste feed rate, (3) combustion temperature, (4) an appropriate indicator of combustion gas 
velocity, (5) allowable variations in incinerator system design or operating procedures, and 
(6) other operating requirements considered necessary to ensure 99.99 percent DRE for the 
POHCs. 


Additionally, Subpan 0 of 40 CFR 246 requires that hazardous waste 
incineration facilities achieve 99-percent emissions reduction of HC1 (if HC1 emissions are 
greater than 1.8 kg/hr [4.0 lb/hr]) and a limit of 180 milligrams per dry standard cubic meter 
(0.0787 grains per dry standard cublic foot) for PM emissions. These emission limits would 
require facilities to apply acid gas/PM control devices. As mentioned in Section 7.3.4, acid 
gas/PM control devices may result in panial control of emissions of organic compounds. 


7-39 



7.4 


EXTERNAL COMBUSTION OF SOLID, LIQUID, AND GASEOUS FUELS 
IN STATIONARY SOURCES FOR HEAT AND POWER GENERATION 


The combustion of solid, liquid, and gaseous fuels such as natural gas, oil, coal, 
and wood waste has been shown to be a minor source of benzene emissions. This section 
addresses benzene emissions from the external combustion of these types of fuels by stationary 
sources that generate heat or power in the utility, industrial/commercial, and residential 
sectors. 

7.4.1 Utility Sector 2 06 

Fossil fuel-fired utility boilers comprise about 72 percent (or 1,696,000 million 
Btu/hr [497,000 megawatts (MW)]) of the generating capacity of U.S. electric power plants. 
The primary fossil fuels burned in electric utility boilers are coal, natural gas, and oil. Of 
these fuels, coal is the most widely used, accounting for 60 percent of the U.S. fossil fuel 
generating capacity. Natural gas represents about 25 percent and oil represents 15 percent of 
the U.S. fossil fuel generating capacity. 

Most of the coal-firing capability is east of the Mississippi River, with the 
significant remainder being in the Rocky Mountain region. Natural gas is used primarily in the 
South Central States and California. Oil is predominantly used in Florida and the Northeast. 
Fuel economics and environmental regulations affect regional use patterns. For example, coal 
is not used m California because of stringent air quality limitations. Information on precise 
utility plant locations can be obtained by contacting utility trade associations such as the 
Electric Power Research Institute in Palo Alto, California (415-855-2000); the Edison Electric 
Institute in Washington, D.C. (202-828-7400); or the U.S. Department of Energy (DOE) in 
Washington, D.C. Publications by EPA/DOE on the utility industry are also useful in 
determining specific facility locations, sizes, and fuel use. 


7-40 



Process Description of Utility Boilers 


A utility boiler consists of several major subassemblies, as shown in 
Figure 7-1 1. 206 These subassemblies include the fuel preparation system, the air supply 
system, burners, the furnace, and the convective heat transfer system. The fuel preparation 
system, air supply, and burners are primarily involved in converting fuel into thermal energy 
in the form of hot combustion gases. The last two subassemblies are involved in the transfer 
of the thermal energy in the combustion gases to the superheated steam required to operate the 
steam turbine and produce electricity. 206 

Three key thermal processes occur in the furnace and convective sections of the 
boiler. First, thermal energy is released during controlled mixing and combustion of fuel and 
oxygen in the burners and furnace. Second, a portion of the thermal energy formed by 
combustion is adsorbed as radiant energy by the furnace walls. The furnace walls are formed 
oy multiple, closely spaced tubes filled with high-pressure water mat carry water from the 
bottom of the furnace to absorb radiant heat energy to the steam drum located at the top of the 
boiler. Third, the gases enter the convective pass of the boiler, and the balance of the energy 
retained by the high-temperature gases is adsorbed as convective energy by the convective heat 
transfer system (superheater, reheater, economizer, and air preheater). 206 

A number of different furnace configurations are used in utility boilers, 
including tangentially fired, wall-fired, cyclone-fired, stoker-fired, and FBC boilers. Some of 
these furnace configurations are designed primarily for coal combustion; others are designed 
for coal, oil, or natural gas combustion. The types of furnaces most commonly used for firing 
oil and natural gas are the tangentially fired and wall-fired boiler designs. 207 One of the 
primary differences between furnaces designed to bum coal versus oil or gas is the furnace 
size. Coal requires the largest furnace, followed by oil, then gas. 206 

The average size of boilers used in the utility sector varies primarily according 
to boiler type. Cyclone-fired boilers are generally the largest, averaging about 850 to 


7-41 


Superheaters and Reheaters 



Flue Gas 


Air 


Figure 7-11. Simplified Boiler Schematic 


Source: Reference 206. 


7-42 


ERQ_POM_4121 .pr# 



















































1,300 million Btu/hr (250 to 380 MW) generating capacity. Tangentially fired and wall-fired 
boiler designs firing coal average about 410 to 1,470 million Btu/hr (120 to 430 MW); these 
designs firing oil and natural gas average about 340 to 920 million Btu/hr (100 to 270 MW). 
Stoker-fired boilers average about 34 to 58 million Btu/hr (1-0 to 17 MW). 207 Additionally, 
unit sizes of FBC boilers range from 85 to 1,360 million Btu/hr (25 to 400 MW), with the 
largest FBC boilers typically closer to 680 million Btu/hr (200 MW). 206 


Tangentially Fired Boiler -The tangentially-fired boiler is based on the concept 
of a single flame zone within the furnace. The fuel-to-air mixture in a tangentially fired boiler 
projects from the four comers of the furnace along a line tangential to an imaginary cylinder 
located along the furnace centerline. When coal is used as the fuel, the coal is pulverized in a 
mill to the consistency of talcum powder (i.e., at least 70 percent of the panicles will pass 
through a 200-mesh sieve), entrained in primary air, and fired in suspension. 208 As fuel and air 
are fed to the burners, a rotating “fireball” is formed to control the furnace exit gas 

^ ^ A n rtpnr-p f p t-h- p o ■*-q f"» 'rp f f\r fr nl fflTTinCT V9T7Qtir\nC 171 T'VtP ■firp'hq]] mov 

kWtuuwiuiUi w cms.* jlw Jillx w a. illLli. w \ Hi iOuu. inw lli wU ci.ll ILicLj 

be moved up and down by tilting the fuel-air nozzle assembly. Tangentially fired boilers 
commonly bum coal (pulverized). However, oil or gas may also be burned. 206 


Wall-Fired Boiler — Wall-fired boilers are characterized by multiple individual 
burners located on a single wall or on opposing walls of the furnace. Refer to Figure 7-12 for 
a diagram of a single wall-fired boiler. 206 As with tangentially fired boilers, when coal is used 
as the fuel, the coal is pulverized, entrained in primary air, and fired in suspension. In 
contrast to tangentially fired boilers, which produce a single flame envelope or fireball, each of 
the burners in a wall-fired boiler has a relatively distinct flame zone. Depending on the design 
and location of the burners, wall-fired boilers consist of various designs, including single-wall, 
opposed-wall, cell, vertical, arch, and turbo. Wall-fired boilers may bum (pulverized) coal, 
oil, or natural gas. 206 


7-43 




Burner B 
Burner A 


Air A- 

AirB- 

Air C 
AirD- 


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Fuel B 

Fuel C 
Fuel D 


Burner D 
Burner C 



Figure 7-12. Single Wall-fired Boiler 


Source: Reference 206. 


7-44 


•Jd ezi* - no<ToM3 

























































































































Cvcione-Fired Boiler --As shown in Figure 7-13, in cyclone-fired boilers, fuel 
and air are burned in horizontal, cylindrical chambers, producing a spinning, high-temperature 
flame. When coal is used, the coal is crushed to a 4-mesh size and admitted with the primary 
air in a tangential fashion. The finer coal particles are burned in suspension and the coarser 
particles are thrown to the walls by centrifugal force. 207 Cyclone-fired boilers are almost 
exclusively coal-fired and bum crushed rather than pulverized coal. However, some units are 
also able to fire oil and natural gas. 206 

Fluidized-Bed Combustion Boiler -Fluidized-bed combustion is a newer boiler 
technology that is not as widely used as the other, conventional boiler types. In a typical FBC 
boiler, crushed coal in combination with inert material (sand, silica, alumina, or ash) and/or 
sorbent (limestone) are maintained in a highly turbulent suspended state by the upward flow of 
primary air from the windbox located directly below the combustion floor. This fluidized state 
provides a large amount of surface contact between the air and solid particles, which promotes 
uniform and efficient combustion at lower furnace temperatures-between 1,575 and 1,650°F 
(860 and 900°C) compared to 2,500 and 2,800°F (1,370 and 1,540°C) for conventional coal- 
fired boilers. Fluidized bed combustion boilers have been developed to operate at both 
atmospheric and pressurized conditions. Refer to Figure 7-14 for a simplified diagram of an 
atmospheric FBC. 200 

Stoker-Fired Boiler -Rather than firing coal in suspension, mechanical stokers 
can be used to bum coal in fuel beds. All mechanical stokers are designed to feed coal onto a 
grate within the furnace. The most common stoker type of boiler used in the utility industry is 
the spreader-type stoker (refer to Figure 7-15 for a diagram of a spreader type stoker 
fired-boiler). 206 Other stoker types are overfeed and underfeed stokers. 

In spreader stokers, a flipping mechanism throws crushed coal into the furnace 
and onto a moving fuel bed (grate). Combustion occurs partly in suspension and partly on the 
grate. 208 In overfeed stokers, crushed coal is fed onto a traveling or vibrating grate from an 
adjustable gate above and bums on the fuel bed as it progresses through the furnace. 


7-45 





SECONDARY 
AIR INLET 


COAL PIPE - 
CRUSHED COAL 
(1/4* Screen 
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Reference 206. 


Figure 7-13. Cyclone Burner 


7-46 


940226-kl-DR T P 

























































Figure 7-14. Simplified Atmospheric Fluidized Bed Combustor Process Flow Diagram 
Source: Reference 206. 


7-47 


ERO POM 4124.ds4 













































7-48 


Figure 7-15. Spreader Type Stoker-fired Boiler - Continuous Ash Discharge Grate 






























Conversely, in underfeed stokers, crushed coal is forced upward onto the fuel bed from below 
by mechanical rams or screw conveyors. 206,208 

Benzene Emissions from Utility Boilers 

Benzene emissions from utility boilers may depend on various factors, including 

9 

(1) type of fossil fuel burned, (2) type of boiler used, (3) operating conditions of the boiler, 
and (4) pollution control device(s) used. As described below, conditions that favor more 
complete combustion of the fuel generally result in lower organic emissions. Emission factors 
for benzene emissions from utility boilers are presented in Table 7-5. 

Table 7-5 presents three benzene emission factors for two types of coal-fired 
boilers utilizing three types of PM/S0 2 /N0 X air pollution control systems. The data show only 
slightly higher benzene emissions from a tangentially fired boiler than a cyclone-fired boiler 
firing coal, and show that there is no significant difference m benzene emissions from the 
different air pollution control device configurations represented. 209 

Table 7-5 also presents two emission factors for two types of natural gas-fired 
boilers utilizing flue gas recirculation. 3,209,210 The data show only slightly higher emissions for 
the opposed-w-all boiler than for the tangentially fired boiler. Additionally, the emission tests 
from which the emission factors were generated demonstrated that changes in unit load and 

excess air level did not significantly impact benzene emissions from either boiler type. 210 

Control Technologies for Utility Boilers 

Utility boilers are highly efficient and generally the best controlled of all 
combustion sources. Baghouses, ESPs, wet scrubbers, and multicyclones have been applied 
for PM control in the utility sector. A combination of a wet scrubber and ESP are often used 
to control both S0 2 and PM emissions. 


7-49 


TABLE 7-5. SUMMARY OF BENZENE EMISSION FACTORS FOR UTILITY BOILERS 


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The above control technologies are not intended to reduce benzene emissions 
from utility boilers. In general, emissions of organic pollutants, including benzene, are 
reduced by operating the furnace in such as way as to promote complete combustion of the 
fossil fuel(s) combusted in the furnace. Therefore, any combustion modification that increases 
the combustion efficiency will most likely reduce benzene emissions. The following conditions 
can increase combustion efficiency: 211 

• Adequate supply of oxygen; 

• Good air/fuel mixing; 

• Sufficiently high combustion temperature; 

• Short combustion gas residence time; and 

• Uniform fuel load (i.e., consistent combustion intensity). 

7 4 2 Industr i al ' C nmmereial Sect or 

Industrial boilers are widely used in manufacturing, processing, mining, and 
refining primarily to generate process steam, electricity, or space heat at the facility. 

However, the industrial generation of electricity is limited, with only 10 to 15 percent of 
industrial boiler coal consumption and 5 to 10 percent of industrial boiler gas and oil 
consumption used for electricity' generation. 212 The use of industrial boilers is concentrated in 
four major industries: pulp and paper, primary metals, chemicals, and minerals. These 
industries account for 82 percent of the total firing capacity. 213 Commercial boilers are used by 
commercial establishments, medical institutions, and educational institutions to provide space 
heating. 

In collecting survey data to support its Industrial Combustion Coordinated 
Rulemaking (ICCR), the EPA compiled information on a total of 69,494 combustion boiler 
units in the industrial and commercial sectors. 213 While this number likely underestimates the 
total population of boilers in the industrial and commercial sectors (due to unreceived survey 


7-51 



responses and lack of information on very small units) it provides an indication of the large 
number of sources included in this category. 

Of the units included in the ICCR survey database, approximately 70 percent 
were classified in the natural gas fuel subcategory, 23 percent in the oil (distillate and residual) 
subcategory, and 6 percent in the coal burning subcategory. These fuel subcategory 
assignments are based on the units burning only greater than 90 percent of the specified fuel 
for that subcategnry All other units (accounting for the other 1 percent of assignments) are 
assigned to a subcategory of “other fossil fuel.” 213 

Other fuels burned in industrial boilers are wood wastes, liquified petroleum 
gas, asphalt, and kerosene. Of these fuels, wood waste is the only non-fossil fuel discussed 
here because benzene emissions were not characterized for combustion of the other fuels. The 
burning of wood waste in boilers is confined to those industries where it is available as a 
byproduct. It is burned both to obtain heat energy and to alleviate possible solid waste disposal 
problems. Generally, bark is the major type of waste burned in pulp mills. In the lumber, 
furniture, and plywood industries, either a mixture of wood and bark waste or wood waste 
alone is most frequently burned. As of 1980, there were approximately 1,600 wood-fired 
boilers operating in the United States, with a total capacity of over 102,381 million Btu/hour 
(30,000 MW). 214 


Industrial and commercial coal combustion sources are located throughout the 
United States, but tend to follow industry and population trends. Most of the coal-fired 
industrial boiler sources are located in the Midwest, Appalachian, and Southeast regions. 
Industrial wood-fired boilers tend to be located almost exclusively at pulp and paper, lumber 
products, and furniture industry facilities. These industries are concentrated in the Southeast, 
Gulf Coast, Appalachian, and Pacific Northwest regions. The Pacific Northwest contains 
many of the boilers firing salt-laden wood bark. 


7-52 


Trade associations such as the American Boiler Manufacturers Association in 
Arlington, Virginia, (703-522-7350) and the Council of Industrial Boiler Owners in Fairfax 
Station, Virginia, (703-250-9042) can provide information on industrial boiler locations and 
trends. 215 


Process Description of Industrial/Commercial Boilers 

Some of the same types of boilers used by the utility sector are also used by the 
industrial/commercial sector; however, the average boiler size used by the 
industrial/commercial sector is substantially smaller. Additionally, a few types of boiler 
designs are used only by the industrial sector. For a general description of the major 
subassemblies of boilers and their key thermal processes, refer to the discussion of utility 
boilers in Section 7.4.1 and Figure 7-11. The following two sections describe 
industrial/commercial boilers that fire fossil fuels and wood waste. 

Fossil Fuel Combustion --All of the boilers used by the utility industry 
(described in Section 7.4.1) are “water-tube” boilers, which means that the water being heated 
flows through tubes and the hot gases circulate outside the tubes. Water-tube boilers represent 
the majority (57 percent) of industrial and commercial boiler capacity (70 percent of industrial 
boiler capacity). 212 Water-tube boilers are used in a variety of applications, ranging from 
supplying large amounts of process steam to providing space heat for industrial and 
commercial facilities. These boilers have capacities ranging from 10 to 1,500 million Btu/hr 
(3 to 440 MW), averaging about 410 million Btu/hr (120 MW). The most common types of 
water-tube boilers used in the industrial/ commercial sector are wall-fired and stoker-fired 
boilers. Tangentially fired and FBC boilers are less commonly used. Refer to Section 7.4.1 
for descriptions of these boiler designs. 213 

The industrial/commercial sector also uses boilers with two other types of heat 
transfer methods: fire-tube and cast iron boilers. Because their benzene emissions have not 
been characterized, these types of boilers are only briefly described below. 


7-53 



In fire-tube boilers, the hot gas flows through the tubes and the water being 
heated circulates outside of the tubes. Fire-tube boilers are not available with capacities as 
large as those of water-tube boilers, but they are also used to produce process steam and space 
heat. Most fire-tube boilers have a capacity between 1.4 and 24.9 million Btu/hour 
(0.4 and7.3 MW thermal). Most installed firetube boilers bum oil or gas. 213 

In cast iron boilers, the hot gas is also contained inside the tubes, which are 
surrounded by the water being heated, but the units are constructed of cast iron instead of 
steel. Cast iron boilers are limited in size and are used only to supply space heat. Cast iron 
boilers range in size from less than 0.3 to 9.9 million Btu/hour (0.1 to 2.9 MW thermal). 213 

Wood Combustion --The burning of wood waste in boilers is mostly confmed to 
those industries where it is available as a byproduct. It is burned both to obtain heat energy 
and to alleviate solid waste disposal problems. Wood waste may include large pieces such as 
slabs, logs and bark strips as well as cuttings, shavings, pellets, and sawdust. 214 

Various boiler firing configurations are used in burning wood waste. One 
common type in smaller operations is the dutch oven or extension type of furnace with a flat 
grate. This unit is widely used because it can bum fuels with very high moisture. Fuel is fed 
into the oven through apertures in a firebox and is fired in a cone-shaped pile on a flat grate. 
The burning is done in two stages: (1) drying and gasification, and (2) combustion of gaseous 
products. The first stage takes place in a cell separated from the boiler section by a bridge 
wall. The combustion stage takes place in the main boiler section. 214 

In another type of boiler, the fuel-cell oven, fuel is dropped onto suspended 
fixed grates and fired in a pile. The fuel cell uses combustion air preheating and positioning of 
secondary and tertiary air injection ports to improve boiler efficiency. 214 

In many large operations, more conventional boilers have been modified to bum 

wood waste. The units may include spreader stokers with traveling grates or vibrating grate 


7-54 



stokers, as well as tangentially fired or cyclone-fired boilers (see Section 7.4.1 for descriptions 
of these types of boilers). The most widely used of these configurations is the spreader stoker, 
which can bum dry or wet wood. Fuel is dropped in front of an air jet that casts the fuel out 
over a moving grate. The burning is done in three stages: (1) drying, (2) distillation and 
burning of volatile matter, and (3) burning of fixed carbon. Natural gas or oil is often fired as 
auxiliary fuel. This is done to maintain constant steam when the wood supply fluctuates or to 
provide more steam than can be generated from the wood supply alone. 214 

Sander dust is often burned in various boiler types at plywood, particle board, 
and furniture plants. Sander dust contains fine wood particles with low moisture content (less 
than 20 percent by weight). It is fired in a flaming horizontal torch, usually with natural gas as 

an ignition aid or supplementary fuel. 214 

A recent development in wood firing is the FBC boiler. Refer to Section 7.4.1 
for 2 description of this boiler type. Because of the large thermal mass represented by the hot 
inert bed particles, FBCs can handle fuels with high moisture content (up to 70 percent, total 
basis). Fluidized beds can also handle dirty fuels (up to 30 percent inert material). Wood 
material is pyrolyzed more quickly in a fluidized bed than on a grate because of its immediate 
contact with hot bed material. Combustion is rapid and results in nearly complete combustion 
of organic matter, minimizing emissions of unbumed organic compounds. 214 

Benzene Emissions from Industrial/Commercial Boilers 

Benzene emissions from industrial/commercial boilers may depend on various 
factors, including (1) type of fuel burned, (2) type of boiler used, (3) operating conditions of 
the boiler, and (4) pollution control device(s) used. Conditions that favor more complete 
combustion of the fuel generally result in lower organic emissions. Additionally, the organic 
emissions potential of wood combustion is generally thought to be greater than that of fossil 
fuel combustion because wood waste has a lower heating value, which may decrease 


7-55 


combustion efficiency. Emission factors for benzene emissions from industrial and 
commercial/institutional boilers are presented in Table 7-6. 3,216 " 220 

Table 7-6 presents emission factors primarily for wood waste combustion. 
Additionally a few emission factors are presented for fossil fuel (residual oil and coke/coal) 
and process gas (landfill gas and POTW digester gas) combustion. Most of the emission 
factors represent emissions from a non-specified type of boiler. Only two boiler types are 
specified (FBC and spreader-stoker). Additionally, the benzene emission factors presented are 
emissions following various types of PM and S0 2 emission control systems. 

In most cases, Table 7-6 specifies the type of wood waste associated with the 

emission factors for wood combustion boilers. The composition of wood waste may have an 
impact on benzene emissions. The composition of wood waste depends largely on the industry 
from which it originates. Pulping operations, for example, produce great quantities of bark 
that may contain more than 70 percent by weight moisture, along with sand and other 
noncombustibles. Because of this, bark boilers in pulp mills may emit considerable amounts of 
organic compounds to the atmosphere unless they are well controlled. On the other hand, 
some operations, such as furniture manufacturing, produce a clean, dry wood waste, 5 to 
50 percent by weight moisture, with relatively low organic emissions when properly burned. 
Still other operations, such as sawmills, bum a varying mixture of bark and wood waste that 
results in paniculate emissions somewhere between those of pulp mills and furniture 
manufacturing. Additionally, when fossil fuels are co-fired with wood waste, the combustion 
efficiency is typically improved; therefore, organic emissions may decrease. 215 

The type of boiler, as well as its operation, affect combustion efficiency and 
emissions. Wood-fired boilers require a sufficiently large refractory surface to ensure proper 
drying of high-moisture-content wood waste prior to combustion. Adequately dried fuel is 
necessary to avoid a decrease in combustion temperatures, which may increase organic 
emissions because of incomplete combustion. 215 


7-56 


TABLE 7-6. SUMMARY OF BENZENE EMISSION FACTORS FOR INI iUSTRIAL 

AND COMMERCIAL/INSTITUTIONAL BOILERS 


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1-02-009-06 Spreader-stoker Wood 1 Multiple 2.43 x 10 D 218 

_ boiler _ cyclone 1 _ (1.05 x 10 4) _ 











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7-58 




















Control Technologies for Industrial/Commercial Boilers 


Control techniques for reducing benzene emissions from industrial and 
commercial boilers are similar to those used for utility boilers. Refer to Section 7.4.1 for a 
discussion of control techniques also applicable to commercial and industrial boilers. 

In Section 7.4.1, various operating conditions are listed that contribute to the 
combustion efficiency of a boiler (e.g., oxygen supply, good air/fuel mixing, and 
temperature). It has been demonstrated for a spreader-stoker boiler firing wood that benzene 
emissions are an order of magnitude lower under good firing conditions than under poor firing 
conditions (when the boiler was in an unsteady or upset condition). It has also been shown that 
the ratio of overfire to underfire air plays an important role in benzene emissions. Based on 
recent test results, the speculation is that if the balance of combustion air heavily favors 
underfire air, there is insufficient combustion air in the upper furnace to complete the 
combustion of PTCs (including benzene) Conversely, with excess overfire air. the flame¬ 
quenching effect of too much combustion air in the upper furnace appears to suppress the 
combustion of PICs at that stage of the combustion process. 218 

7.4.3 Residential Sector 


The residential sector includes furnaces and boilers burning coal, oil, and 
natural gas, stoves and fireplaces burning wood, and kerosene heaters. All of these units are 
designed to heat individual homes. Locations of residential combustion sources are tied 
directly to population trends. Coal consumption for residential combustion purposes occurs 
mainly in the Northeast, Appalachian, and Midwest regions. Residential oil consumption is 
greatest in the Northeast and Mid-Atlantic regions. Wood-fired residential units are generally 
concentrated in heavily forested areas of the United States, which reflects fuel selection based 
on availability and price. 215 


7-59 



Process Description for Residential Furnaces, Boilers, Stoves, and Fireplaces 

The following sections describe the types of residential furnaces, boilers, stoves, 
and fireplaces that fire wood, coal, oil, natural gas, kerosene. 

Wood Combustion —Residential wood combustion generally occurs in either a 
wood-fired stove or fireplace unit located inside the house. The following discussion describes 
the specific characterization of woodstoves, followed by a discussion on fireplaces. 

Woodstoves are commonly used in residences as space heaters. They are used 
both as the primary source of residential heat and to supplement conventional heating systems. 
Wood stoves have varying designs based on the use or non-use of baffles and catalysts, the 
extent of combustion chamber sealing, and differences in air intake and exhaust systems. 

The EPA has identified five different categories of wood-burning stoves based 

on differences in both the magnitude and the composition of the emissions: 221 

• Conventional woodstoves; 

• Noncatalytic woodstoves; 

• Catalytic woodstoves; 

• Pellet stoves; and 

• Masonry heaters. 

Within these categories, there are many variations in device design and operation. 

The conventional stove category comprises all stoves that do not have catalytic 
combustors and are not included in the other noncatalytic categories (i.e., noncatalytic and 
pellet). Conventional stoves do not have any emissions reduction technology or design 
features and, in most cases, were manufactured before July 1, 1986. Stoves of many different 


7-60 



airflow designs may be included in this category, such as updraft, downdraft, crossdraft and 
S-flow. 221 

Noncatalytic woodstoves are those units that do not employ catalysts but do have 
emissions-reducing technology or features. Typical noncatalytic design includes baffles and 
secondary combustion chambers. 221 

Catalytic stoves are equipped with a ceramic or metal honeycomb device, called 
a combustor or converter, that is coated with a noble metal such as platinum or palladium. 

The catalyst material reduces the ignition temperature of the unbumed VOC and CO in the 
exhaust gases, thus augmenting their ignition and combustion at normal stove operating 

temperatures. As these components bum, the temperamre inside the catalyst increases to a 
point at which the ignition of the gases is essentially self-sustaining. 221 


Pellet stoves axe those fueled with pellets of sawdust, wood products, and other 

biomass materials pressed into manageable shapes and sizes. These stoves have active air flow 
systems and unique grate design to accommodate this type of fuel. Some pellet stove models 
are subject to the 1988 NSPS; others are exempt because of their high air-to-fuel ratio (greater 


than 35-to-l). 


121 


Masonry heaters are large, enclosed chambers made of masonry products or a 
combination of masonry products and ceramic materials. These devices are exempt from the 
1988 NSPS because of their weight (greater than 800 kg). Masonry heaters are gaining 
popularity as a cleaner-burning and heat-efficient form of primary and supplemental heat, 
relative to some other types of wood heaters. In a masonry heater, a complete charge of wood 
is burned in a relatively short period of time. The use of masonry materials promotes heat 
transfer. Thus, radiant heat from the heater warms the surrounding area for many hours after 
the fire has burned out. 221 


7-61 


Fireplaces are used primarily for aesthetic effects and secondarily as a 
supplemental heating source in houses and other dwellings. Wood is the most common fuel for 
fireplaces, but coal and densified wood “logs” may also be burned. 222 The user intermittently 
adds fuel to the fire by hand. 

Fireplaces can be divided into two broad categories: (1) masonry (generally 
brick and/or stone, assembled on site, and integral to a structure) and (2) prefabricated (usually 
metal, installed on site as a package with appropriate duct work). Masonry fireplaces typically 
have large, fixed openings to the fire bed and dampers above the combustion area in the 
chimney to limit room air and heat losses when the fireplace is not being used. Some masonry 
fireplaces are designed or retrofitted with doors and louvers to reduce the intake of combustion 
air during use. 222 

Prefabricated fireplaces are commonly equipped with louvers and glass doors to 
reduce the intake of combustion air, and some are surrounded by ducts through which 
floor-level air is drawn by natural convection, heated, and returned to the room. Many 
varieties of prefabricated fireplaces are now on the market. One general class is the 
freestanding fireplace, the most common of which consists of an inverted sheet metal funnel 
and stovepipe directly above the fire bed. Another class is the “zero clearance” fireplace, an 
iron or heavy-gauge steel firebox lined inside with firebrick and surrounded by multiple steel 
walls with spaces for air circulation. Some zero clearance fireplaces can be inserted into 
existing masonry fireplace openings, and thus are sometimes called “insens.” Some of these 
units are equipped with close-fitting doors and have operating and combustion characteristics 
similar to those of woodstoves. 222 

Masonry fireplaces usually heat a room by radiation, with a significant fraction 
of the combustion heat lost in the exhaust gases and through fireplace walls. Moreover, some 
of the radiant heat entering the room goes toward warming the air that is pulled into the 
residence to make up for that drawn up the chimney. The net effect is that masonry fireplaces 
are usually inefficient heating devices. Indeed, in cases where combustion is poor, where the 


7-62 


outside air is cold, or where the fire is allowed to smolder (thus drawing air into a residence 
without producing appreciable radiant heat energy), a net heat loss may occur in a residence 
using a fireplace. 

Fireplace heating efficiency may be improved by a number of measures that 
either reduce the excess air rate or transfer back into the residence some of the heat that would 
normally be lost in the exhaust gases or through fireplace walls. As noted above, such 
measures are commonly incorporated into prefabricated units. As a result, the energy 
efficiencies of prefabricated fireplaces are slightly higher than those of masonry fireplaces. 222 

Coal Combustion -Coal is not a widely used source of fuel for residential 
heating purposes in the United States. Only 0.3 percent of the total coal consumption in 1990 
was for residential use. 223 However, combustion units burning coal may be sources of benzene 
emissions and may be important local sources in areas that have a large number of residential 
houses tnat rely on tms ruei tor neatmg. 

There are a wide variety of coal-burning devices in use, including boilers, 
furnaces, coal-burning stoves, and wood-burning stoves that bum coal. These units may be 
hand fed or automatic feed. Boilers and warm-air furnaces are usually stoker-fed and are 
automatically controlled by a thermostat. The stove units are less sophisticated, generally hand 
fed, and less energy-efficient than boilers and furnaces. Coal-fired heating units are operated 
at low temperatures and do not efficiently combust fuel. 215 Therefore, the potential for 
emissions of benzene exists. 

Distillate Oil Combustion -The most frequently used home heating oil in the 
United States is No. 2 fuel oil, otherwise referred to as distillate oil. Distillate oil is the 
second most important home heating fuel behind natural gas. 224 The use of distillate oil-fired 
heating units is concentrated in the Northeast portion of the United States. Connecticut, 

Maine, Massachusetts, New Hampshire, Rhode Island, Vermont, Delaware, District of 


7-63 




Columbia, Maryland, New Jersey, New York, and Pennsylvania accounted for approximately 
72 percent of the residential share of distillate oil sales. 225 

Residential oil-fired heating units exist in a number of design and operating 
variations related to burner and combustion chamber design, excess air, heating medium, etc. 
Residential systems typically operate only in an “on” or “off’ mode, with a constant fuel firing 
rate, as opposed to commercial and industrial applications, where load modulation is used. 226 
In distillate oil-fired heating units, pressure or vaporization is used to atomize fuel oil in an 
effort to produce finer droplets for combustion. Finer droplets generally mean more complete 
combustion and less organic emissions. 

When properly tuned, residential oil furnaces are relatively clean burning, 
especially as compared to woodstoves. 224 However, another study has shown that in practice 
not all of the fuel oil is burned and tiny droplets escape the flame and are carried out in the 
exhaust. 227 This study also concluded that most of the organic emissions from an oil furnace 
are due to the unbumed oil (as opposed to soot from the combustion process), especially in the 
more modem burners that use a retention head burner, where over 90 percent of the carbon in 
the emissions was from unbumed fuel. 227 

Natural Gas Combustion -Natural gas is the fuel most widely used for home 
heating purposes, with more than half of all the homes being heated through natural gas 
combustion. Gas-fired residential heating systems are generally less complex and easier to 
maintain than oil-burning units because the fuel bums more cleanly and no atomization is 
required. Most residential gas burners are typically of the same basic design. They use 
natural aspiration, where the primary air is mixed with the gas as it passes through the 
distribution pipes. Secondary air enters the furnace around the burners. Flue gases then pass 
through a heat exchanger and a stack. As with oil-fired systems, there are usually no pollution 
control equipment installed on gas systems, and excess air, residence time, flame retention 
devices, and maintenance are the key factors in the control of emissions from these units. 


7-64 



Kerosene Combustion —The sale and use of kerosene space heaters increased 
dramatically during the 1980s and they continue to be sold and used throughout the United 
States as supplementary and, in some cases, as primary home heating sources. 228 These units 
are usually unvented and release emissions inside the home. There are two basic types of 
kerosene space heaters: convective and radiant. 

Emission Factors for Residential Furnaces, Boilers, Stoves, and Fireplaces 

The combustion of fossil fuels or wood in residential units is a relatively slow 
and low-temperature process. Studies do not indicate the cause(s) for benzene formation in the 
residential sector; however, the mechanism may be similar to that in industrial boilers and 
utility boilers. Benzene may be formed through incomplete combustion. Because combustion 
in the residential sector tends to be less efficient than in other sectors, the potential to form 
benzene may be greater. 

Table 7-7 presents emission factors for uncontrolled benzene emissions from 
both catalytic and non-catalytic woodstoves. 3 Benzene emission factors for other types of 

a 

residential wood combustion sources are not presented because of limited data. 

In general, emissions of benzene can vary widely depending on how the units 
are operated and the how emissions are measured. The following factors may affect benzene 

emissions measured from residential wood combustion sources: 

• Unit design and degree of excess air; 

• Wood type, moisture content, and other wood characteristics; 

• Bum rate and stage of bum; and 

• Firebox and chimney temperatures. 


7-65 



TABLE 7-7. SUMMARY OF BENZENE EMISSION FACTORS FOR RESIDENTIAL WOODSTOVES 


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Control Techniques for Residential Furnaces, Boilers, Stoves, and Fireplaces 

Residential combustion sources are generally not equipped with PM or gaseous 
pollutant control devices. In coal- and wood-fired sources, stove design and operating practice 
changes have been made to lower PM, hydrocarbon, and CO emissions. Changes include 
modified combustion air flow control, better thermal control and heat storage, and the use of 
combustion catalysts. Such changes may lead to reduced benzene emissions. 

Woodstove emissions reduction features include baffles, secondary combustion 
chambers, and catalytic combustors. Catalytic combustors or convertors are similar to those 
used in automobiles. Woodstove control devices may lose efficiency over time. Control 

degradation for any stoves, including noncatalytic woodstoves, may occur as a result of 
deteriorated seals and gaskets, misaligned baffles and bypass mechanisms, broken refractories, 
or other damaged functional components. 221 In addition, combustion efficiencies may be 

affected by differences in the sealing of the chamber and control of the intake and exhaust 
svstems. 215 

7.5 STATIONARY INTERNAL COMBUSTION 

Stationary internal combustion (IC) sources are grouped into two categories: 

reciprocating engines and gas turbines. Stationary IC engines and turbines are principally used 
for electricity generation and industrial applications such as natural gas processing, and oil and 
gas exploration, production and transmission. 229 

7.5.1 Reciprocating Engines 

Process Description for Reciprocating Engines 

Reciprocating engines may be classified into two types: spark and compression 
ignition (diesel). However, all reciprocating IC engines operate by the same basic process 


7-67 



depicted in Figure 7-16. 230 A combustible mixture is first compressed in a small volume 
between the head of a piston and its surrounding cylinder. - The mixture is then ignited and the 
resulting high-pressure products of combustion push the piston through the cylinder. This 
movement is converted from linear to rotary motion by a crankshaft. The piston returns, 
pushing out exhaust gases, and the cycle is repeated. 231 

All diesel-fueled engines are compression-ignited and all gasoline and natural 
gas fueled engines are spark-ignited; however, natural gas can be used in a compression 
ignition engine, as discussed below. The two types of reciprocating IC engines, spark ignition 
and compression ignition, are discussed below, according to the following types of fuel: 
distillate oil (diesel), gasoline, and natural gas. 

Distillate Oil (DieseP ~In compression ignition engines, more commonly known 
as diesel engines, combustion air is first compression-heated in the cylinder, and fuel is then 
injected into the hot air Ignition is spontaneous because the air is above the auto-ignition 
temperature of the fuel. All distillate oil reciprocating engines are compression-ignited. 

Diesel engines usually operate at a higher compression ratio (ratio of cylinder 
volume when the piston is at the bottom of its stroke to the volume when it is at the top) than 
spark-ignited engines because fuel is not present during compression; hence, there is no danger 
of premature auto-ignition. Because engine thermal efficiency rises with increasing pressure 
ratio (and pressure ratio varies directly with compression ratio), diesel engines are more 
efficient than spark-ignited engines. This increased efficiency is gained at the expense of 
poorer response to load changes and a heavier structure to withstand the higher pressures. 232 

The primary domestic use of large stationary diesel engines (greater than 600 hp 
[447 kW]) is in oil and gas exploration and production. These engines, in groups of three to 
five, supply mechanical power to operate drilling (rotary table), mud pumping, and hoisting 
equipment, and may also operate pumps or auxiliary power generators. Another frequent 
application of large stationary diesel engines is electricity generation for both base and standby 


7-68 



d±aa-PKoeo*6 






7-69 


Figure 7-16. Basic Operation of Reciprocating Internal Combustion Engines 








































































































service. Smaller uses of large diesel engines include irrigation, hoisting, and nuclear power 
plant emergency cooling water pump operation. The category of smaller diesel engines (up to 
600 hp [447 kW]) covers a wide variety of industrial applications such as aerial lifts, fork lifts, 
mobile refrigeration units, generators, pumps, industrial sweepers/scrubbers, material handling 
equipment (such as conveyors), and portable well-drilling equipment. The rated power of 
these engines can be up to 250 hp (186 kW), and substantial differences in engine duty cycles 
exist. 232 


Gasoline -Spark ignition initiates combustion by the spark of an electrical 
discharge. Usually, fuel is mixed with the air in a carburetor, but occasionally fuel is injected 
into the compressed air in the cylinder. All gasoline reciprocating engines are spark-ignited. 
Gasoline engines up to 600 hp (447 kW) can be used interchangeably with diesel IC engines in 
the same industrial applications described previously. As with diesel engines, substantial 
differences in gasoline engine duty cycles exist. 231 

Natural Gas -Most reciprocating IC engines that use natural gas are of the 
spark-ignited type. As with gasoline engines, the gas is first mixed with the combustion air at 
an intake valve, but occasionally the fuel is injected into the compressed air in the cylinder. 
Natural gas can be used in a compression ignition engine, but only if a small amount of diesel 
fuel is injected into the compressed air/gas mixture to initiate combustion; hence the name 
dual-fuel engine. Dual-fuel engines were developed to obtain compression ignition 
performance and the economy of natural gas, using a minimum of 5 to 6 percent diesel fuel to 
ignite the natural gas. Large dual-fuel engines have been used almost exclusively for prime 
electric power generation. 231 

Natural gas-fired stationary IC engines are also used in the natural gas industry, 
primarily to power compressors used for pipeline transportation, field gathering (collecting gas 
from wells), underground storage, and gas processing plant applications (i.e., prime movers). 
Pipeline engines are concentrated in the major gas-producing states (such as those along the 
Gulf Coast) and along the major gas pipelines. 233 


7-70 




Reciprocating IC engines used in the natural gas industry are separated into 
three design classes: two-stroke lean bum, four-stroke lean bum, and four-stroke rich bum. 
Each of these have design differences that affect both baseline emissions as well as the 
potential for emissions control. Two-stroke engines complete the power cycle in a single 
engine revolution compared to two revolutions for four-stroke engines. With the two-stroke 
engine, the fuel/air charge is injected with the piston near the bottom of the power stroke. The 
valves are all covered or closed and the piston moves to the top of the cylinder compressing the 
charge. Following ignition and combustion, the power stroke starts with the downward 
movement of the piston. Exhaust ports or valves are then uncovered to remove the combustion 
products, and a new fuel/air charge is ingested. Two-stroke engines may be turbocharged 
using an exhaust-powered turbine to pressurize the charge for injection into the cylinder. 
Non-turbocharged engines may be either blower-scavenged or piston-scavenged to improve 
removal of combustion products. 233 

F^u r -strok? engines use a separate engine revolution for the intake/compression 

stroke and the power/exhaust stroke. These engines may be either naturally aspirated, using 
the suction from the piston to entrain the air charge, or turbocharged, using a turbine to 
pressurize the charge. Turbocharged units produce a higher power output for a given engine 
displacement, whereas naturally aspirated units have lower initial cost and maintenance. 
Rich-burn engines operate near the fuel/air stoichiometric limit, with exhaust excess oxygen 
levels less than 4 percent. Lean-bum engines may operate up to the lean flame extinction 
limit, with exhaust oxygen levels of 12 percent or greater. 233 

Pipeline population statistics show a nearly equal installed capacity of 
reciprocating IC engines and turbines. Gas turbines emit considerably smaller amounts of 
pollutants than do reciprocating engines; however, reciprocating engines are generally more 
efficient in their use of fuel. For reciprocating engines, two-stroke designs contribute 
approximately two-thirds of installed capacity in this industry. 233 


7-71 


Benzene Emissions From Reciprocating IC Engines 


Most of the pollutants from IC engines are emitted through the exhaust. 
However, some hydrocarbons escape from the crankcase as a result of blowby (gases that are 
vented from the oil pan after they have escaped from the cylinder past the piston rings) and 
from the fuel tank and carburetor because of evaporation. Nearly all of the hydrocarbons from 
diesel engines enter the atmosphere from the exhaust. Crankcase blowby is minor because 
hydrocarbons are not present during compression of the charge. Evaporative losses are 
insignificant in diesel engines because of the low volatility of diesel fuels. In general, 
evaporative losses are also negligible in engines using gaseous fuels because these engines 
receive their fuel continuously from a pipe rather than via a fuel storage tank and fuel pump. 


Emission factors for uncontrolled benzene emissions from the following 
reciprocating engine types and fuel combinations are provided in Table 7-8: 

(1) reciprocating/distillate oil and publically owned treatment works (POTW) digester gas, 

(2) cogeneration/distillate oil, (3) 2-cycle lean bum/natural gas, (4) large bore engine/distillate 
oil, and (5) large bore engine/distillate oil and gas (dual fuel). Additionally, an emission factor 
for benzene emissions after a non-selective catalytic reduction control device is provided for a 
natural gas-fired, 4-cycle, lean-bum reciprocating engine. 3,231 ' 233 


Control Technologies for Reciprocating Engines 


Control measures for large stationary diesel engines to date have been directed 
mainly at limiting NO x emissions, the primary pollutant from this group of IC engines. All of 
these controls are engine control techniques except for the selective catalytic reduction (SCR) 
technique, which is a post-combustion control. As such, all of these controls usually affect the 
emissions profile for other pollutants as well, and not always positively. The effectiveness of 
controls on a particular engine will depend on the specific design of each engine, and the 
effectiveness of each technique can vary considerably. 


7-72 


TABLE 7 - 8 . SUMMARY OF BENZENE EMISSION I ACTORS FOR RECIPROC \TING ENGINES 


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NSCR = nonselective catalytic reduction. 
POTW = publically owned treatment works. 
























Other NO x control techniques include internal/external exhaust gas recirculation 
(EGR), combustion chamber modification, manifold air cooling, and turbocharging. Various 
other emissions reduction technologies may be applicable to the smaller diesel and gasoline 
engines. These technologies are categorized into fuel modifications, engine modifications, and 
exhaust treatments. 

7.5.2 Gas Turbines 

Stationary gas turbines are applied in electric power generators, in gas pipeline 
pump and compressor drives, and in various process industries. Gas turbines (greater than 
3 MW(e)] are used in electrical generation for continuous, peaking, or standby power. 79 In 
1990, the actual gas-fired combustion turbine generating capacity for electric utilities was 
8,524 MW. 234 The current average size of electricity generation gas turbines is approximately 
31 MW. Turbines are also used in industrial applications, but information was not available to 
estimate their installed capacity. 

The same fuels used in reciprocating engines are combusted to drive gas 
turbines. The primary fuels used are natural gas and distillate (No. 2) fuel oil, although 
residual fuel oil is used in a few applications. 235 The liquid fuel used must be similar in 
volatility to diesel fuel to produce droplets that penetrate sufficiently far into the combustion 
chamber to ensure efficient combustion even when a pressure atomizer is used. 230 

Process Description for Gas Turbines 

Gas turbines are so named not because they are gas-fired, but because 
combustion exhaust gas drives the turbine. Unlike reciprocating engines, gas turbines operate 
in steady flow. As shown in Figure 7-17, a basic gas turbine consists of a compressor, a 
combustor, and a turbine. 230 Combustion air enters the turbine through a centrifugal 


7-74 



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Figure 7-17. Gas Turbine Fngine Configuration 


















compressor, where the pressure is raised to 5 to 30 atmospheres, depending on load and the 
design of the engine. Part of the air is then introduced into the primary combustion zone, into 
which fuel is sprayed. The fuel burns in an intense flame. Gas volume increases with 
combustion, so as the gases pass at high velocity through the turbine, they generate more work 
than is required to drive the compressor. This additional work is delivered by the turbine to a 
shaft to drive an electric power generator or other machinery. 230 

Gas turbines may be classified into three general types: simple-open-cycle, 
regenerative-open-cycle, and combined-cycle. In the simple-open-cycle, the hot gas discharged 
from the turbine is exhausted to the atmosphere. In the regenerative-open-cycle, the gas 
discharged from the turbine is passed through a heat exchanger to preheat the combustion air. 
Preheating the air increases the efficiency of the turbine. In the combined-cycle, the gas 
discharged from the turbine is used as auxiliary heat for a steam cycle. Regenerative-type gas 
turbines constitute only a very small fraction of the total gas turbine population. Identical gas 
turbines used m me combined-cycle and in me simple-cycle tend to exhibit the same emissions 
profiles. Therefore, usually only emissions from simple-cycles are evaluated. 229 

Benzene Emissions From Gas Turbines 

Table 7-9 presents emission factors for controlled benzene emissions from two 
gas turbines utilized for electricity generation. 3 

Control Technologies for Gas Turbines 

As with reciprocating engines, NO x is the primary pollutant from gas turbines 
that controls have been directed at, and techniques for its control still have ramifications for 
the emissions profiles of other pollutants such as hydrocarbons (including benzene). 


7-76 



TABLE 7-9. SUMMARY OF BENZENE EMISSION FACTORS FOR GAS TURBINES 




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Water/steam injection is the most prevalent NO x control for 
cogeneration/combined-cycle gas turbines. Water or steam is injected with air and fuel into the 
turbine combustor in order to lower the peak temperatures, which in turn decreases the NO x 
produced. The lower average temperature within the combustor may produce higher levels of 
CO and hydrocarbons as a result of incomplete combustion. 235 


As described in the previous section, SCR is a post-combustion control that 
selectively reduces NO x by reaction of ammonia and NO on a catalytic surface to form N 2 and 
H 2 0. Although SCR systems can be used alone, all existing applications of SCR have been 
used in conjunction with water/steam injection controls. For optimum SCR operation, the flue 
gas must be within a temperature range of 600 to 800°F (315 to 427°C), with the precise 
limits dependent on the catalyst. Some SCR systems also utilize a CO catalyst to give 
simultaneous catalytic CO/NO x control. 235 


Advanced combustor designs are currently being phased into production 
turbines. These dry techniques decrease turbine emissions by modifying the combustion 
mixing, air staging, and flame stabilization to allow operation at a much leaner air/fuel ratio 
relative to normal operation. Operating at leaner conditions will lower peak temperatures 
within the primary flame zone of the combustor. The lower temperatures may also increase 
CO and hydrocarbon emissions. 235 

With the advancement of NO x control technologies for gas turbines, the 
emission factors for the installed gas turbine population are quite different than for 
uncontrolled turbines. However, uncontrolled turbine emissions have not changed 
significantly. A careful review of specific turbine details should be performed before applying 
uncontrolled emission factors. Today, most gas turbines are controlled to meet local, State, 
and Federal regulations. 235 


7-78 


7.6 


SECONDARY LEAD SMELTING 


In 1990, primary and secondary smelters in the United States produced 
1,380,000 tons (1,255,000 Mg) of lead. Secondary lead smelters produced 946,000 tons 
(860,000 Mg) or about 69 percent of the total refined lead produced in 1990; primary smelters 
produced 434,000 tons (395,000 Mg). Table 7-10 lists U.S. secondary lead smelters according 
to their annual lead production capacity. 236 

7.6.1 Process Description 

The secondary lead smelting industry produces elemental lead and lead alloys by 
reclaiming lead, mainly from scrap automobile batteries. Blast, reverberatory, rotary, and 
electric furnaces are used for smelting scrap lead and producing secondary lead. Smelting is 
the reduction of lead compounds to elemental lead in a high-temperature furnace. It requires 
higher temperature* (2 200 to 2.300°F [1.200 to 1.260°C]) than those required for melting 
elemental lead (621 °F [327°C]). Secondary lead may be refmed to produce soft lead (which is 
nearly pure lead) or alloyed to produce hard lead alloys. Most of the lead produced by 
secondary lead smelters is hard lead, which is used in the production of lead-acid batteries. 236 

Lead-acid batteries represent about 90 percent of the raw materials at a typical 
secondary lead smelter, although this percentage may vary from one plant to the next. These 
batteries contain approximately 18 lb (8.2 kg) of lead per battery consisting of 40 percent lead 
alloys and 60 percent lead oxide. Other types of lead-bearing raw materials recycled by 
secondary lead smelters include drosses (lead-containing byproducts of lead refining), which 
may be purchased from companies that perform lead alloying or refining but not smelting; 
battery plant scrap, such as defective grids or paste; and scrap lead, such as old pipes or roof 
flashing. Other scrap lead sources include cable sheathing, solder, and babbitt metal. 236 

As illustrated in Figure 7-18, the normal sequence of operations in a secondary 
lead smelter is scrap receiving, charge preparation, furnace smelting, and lead refining and 


7-79 



TABLE 7-10. U.S. SECONDARY LEAD SMELTERS 


Smelter 

Location 

Small-Capacity: less than 22.000 tons (20.000 Mg') 


Delatte Metals 

Ponchatoula, LA 

General Smelting and Refining Company 

College Grove, TN 

Master Metals, Inc. 

Cleveland, OH 

Metals Control of Kansas 

Hillsboro, KS 

Metals Control of Oklahoma 

Muskogee, OK 

Medium-Capacity: 22.000 to 82.000 tons (20.000 to 75.000 Mg') 


Doe Run Company 

Boss, MO 

East Penn Manufacturing Company 

Lyon Station, PA 

Exide Corporation 

Muncie, IN 

Exide Corporation 

Reading, PA 

GNB, Inc. 

Columbus, GA 

GNB, Inc. 

Frisco, TX 

Gulf Coast Recycling, Inc. 

Tampa, FL 

Refined Metals Corporation 

Beech Grove, IN 

Refined Metals Corporation 

Memphis, TN 

RSR Corporation 

City of Industry, CA 

RSR Corporation 

Middletown, NY 

Schuylkill Metals Corporation 

Forest City, MO 

Tejas Resources, Inc. 

Terrell, TX 

Laree-Capacitv: greater than 82.000 tons (75.000 Mg'i 


Gopher Smelting and Refining, Inc. 

Eagan, MN 

GNB, Inc. 

Vernon, CA 

RSR Corporation 

Indianapolis, IN 

Sanders Lead Company 

Troy, AL 

Schuylkill Metals Corporation 

Baton Rouge, LA 


Source: Reference 236. 


7-80 










Battarias Arrtva 
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Figure 7-18. Simplified Process Flow Diagram for Secondary Lead Smelting 
Source: Reference 236 


7-81 






















alloying. 236 In the majority of plants, scrap batteries are first sawed or broken open to remove 
the lead alloy plates and lead oxide paste material. The removal of battery covers is typically 
accomplished using an automatic battery feed conveyor system and a slow-speed saw. 
Hammermills or other crushing/shredding devices are then used to break open the battery 
cases. Float/sink separation systems are typically used to separate plastic battery parts, lead 
terminals, lead oxide paste, and rubber parts. The majority of lead smelters recover the 
crushed plastic materials for recycling. Rubber casings are usually landfilled. 


Paste desulfurization, an optional lead recovery step used by secondary lead 
smelters, requires the separation of lead sulfate and lead oxide paste from the lead grid metal, 
polypropylene plastic cases, separators, and hard rubber battery cases. Paste desulfurization 
involves the chemical removal of sulfur from the lead banery paste. The process improves 
furnace efficiency by reducing the need for fluxing agents to reduce lead-sulfur compounds to 
lead metal. The process also reduces S0 2 furnace emissions. However, S0 2 emissions 
reduction is usually a less important consideration because many plants that perform paste 
desulfurization are also equipped with S0 2 scrubbers. About half of all smelters perform paste 
desulfurization. 


After removing the lead components from the charge batteries, the lead scrap is 
combined with other charge materials such as refining drosses, flue dust, furnace slag, coke, 
limestone, sand, and scrap iron and fed to either a reverberatory, blast, rotary or electric 
smelting furnace. Smelting furnaces are used to produce crude lead bullion, which is refined 
and/or alloyed into final lead products. 

Refining, the final step in secondary lead production, consists of removing 
impurities and adding alloying metals to the molten lead obtained from the smelting furnaces to 
meet a customer's specifications. Refining kettles are used for the purifying and alloying of 
molten lead. 


7-82 



Blast and reverberatory furnaces are currently the most common types of 
smelting furnaces in the industry, although some new plants are using rotary furnaces. There 
are currently about 15 reverberatory furnaces, 24 blast furnaces, 5 rotary furnaces, and 
1 electric furnace in the secondary lead industry. 236 The following discussion provides process 
descriptions of these four types of secondary lead smelters. 

Reverberatory Furnaces 

A reverberatory furnace (Figure 7-19) is a rectangular refractory-lined 
furnace. 236 Reverberatory furnaces are operated on a continuous basis. Natural gas- or fuel 
oil-fired jets located at one end or at the sides of the furnace are used to heat the furnace and 
charge material to an operating temperature of about 2,000°F (1,100°C). Oxygen enrichment 
may be used to decrease the combustion air requirements. Reverberatory furnaces are 
maintained at negative pressure by an induced draft fan. 

Reverberatory furnace charge materials include battery grids and paste, battery 
plant scrap, rerun reverberatory furnace slag, flue dust, drosses, iron, silica, and coke. A 
typical charge over one hour may include 9.3 tons (8.4 Mg) of grids and paste to produce 

6.2 tons (5.6 Mg) of lead. 236 

Charge materials are often fed to a natural gas- or oil-fired rotary drying kiln, 
which dries the material before it reaches the furnace. The temperature of the drying kiln is 
about 400 °F (200 °C), and the drying kiln exhaust is drawn directly into the reverberatory 
furnace or ventilated to a control device. From the rotary drying kiln, the feed is either 
dropped into the top of the furnace through a charging chute, or fed into the furnace at fixed 
intervals with a hydraulic ram. In furnaces that use a feed chute, a hydraulic ram is often used 
as a stoker to move the material down the furnace. 

Reverberatory furnaces are used to produce a soft (nearly pure) lead product and 
a lead-bearing slag. This is done by controlling the reducing conditions in the furnace so that 


7-83 


( herge Chute 


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7-84 


Figure 7-19. Cross-sectional View of a Typiral Stationary Reverberatory Furnace 























































































































































































lead components are reduced to metallic lead bullion and the alloying elements (antimony, tin, 
arsenic) in the battery grids, posts, straps, and connectors are oxidized and removed in the 
slag. The reduction of PbS0 4 and PbO is promoted by the carbon-containing coke added to the 
charge material: 


PbS0 4 + C - Pb + C0 2 + S0 2 
2PbO + C - 2Pb + C0 2 

The PbS0 4 and PbO also react with the alloying elements to form lead bullion 
and oxides of the alloying elements, which are removed in the slag. 

The molten lead collects in a pool at the lowest part of the hearth. Slag collects 
in a layer on top of this pool and retards further oxidation of the lead. The slag is made up of 
molten fluxing agents such as iron, silica, and lime, and typically has significant quantities of 
lead. Slag is usually tapped continuously and lead is tapped intermittently. The slag is tapped 
into a crucible. The slag tap and crucible are hooded and vented to a control device. 
Reverberatory furnace slag usually has a high lead content (as much as 70 percent by weight) 
and is used as feed material in a blast or electric furnace to recover the lead content. 
Reverberatory furnace slag may also be rerun through the reverberatory furnace during special 
slag campaigns before being sent to a blast or electric furnace. Lead may be tapped into a 
crucibie or directly into a holding kettle. The lead tap is usually hooded and vented to a 
control device. 236 

Blast Furnaces 

A blast furnace (Figure 7-20) is a vertical furnace that consists of a crucible with 
a vertical cylinder affixed to the top. The crucible is refractory-lined and the vertical cylinder 
consists of a steel water jacket. Oxygen-enriched combustion air is introduced into the furnace 
through tuyeres located around the base of the cylinder. 


7-85 



Figure 7-20. Cross Section of a Typical Blast Furnace 


7-86 


ERG_Lead_44.pre 



















































































































Charge materials are pre-weighed to ensure the proper mixture and then 
introduced into the top of the cylinder using a skip hoist, a conveyor, or a front-end loader. 

The charge fills nearly the entire cylinder. Charge material is added periodically to keep the 
level of the charge at a consistent working height while lead and slag are tapped from the 
crucible. Coke is added to the charge as the primary fuel, although natural gas jets may be 
used to start the combustion process. Combustion is self-sustaining as long as there is 
sufficient coke in the charge material. Combustion occurs in the layer of the charge nearest the 
tuyeres. 


At plants that operate only blast furnaces, the lead-bearing charge materials may 
include broken battery components, drosses from the refining kettles, agglomerated flue dust, 

and lead-bearing slag. A typical charge over one hour may include 4.8 tons (4.4 Mg) of grids 
and paste, 0.3 tons (0.3 Mg) of coke, 0.1 tons (0.1 Mg) of calcium carbonate, 0.07 tons 
(0.06 Mg) of silica, 0.5 tons (0.4 Mg) of cast iron, and 0.2 tons (0.2 Mg) of rerun blast 
furnace slag, to p r oduce 3 7 tons (3.3 Mg') of lead At plant* that also have a reverberatorv 
furnace, the charge materials will also include lead-bearing reverberatory furnace slag. 236 

Blast furnaces are designed and operated to produce a hard (high alloy content) 
lead product by achieving more reducing furnace conditions than those typically found in a 
reverberator}' furnace. Fluxing agents include iron, soda ash, limestone, and silica (sand). 

The oxidation of the iron, limestone, and silica promotes the reduction of lead compounds and 
prevents oxidation of the lead and other metals. The soda ash enhances the reaction of PbS0 4 
and PbO with carbon from the coke to reduce these compounds to lead metal. 

Lead tapped from a blast furnace has a higher content of alloying metals (up to 
25 percent) than lead produced by a reverberatory furnace. In addition, much less of the lead 
and alloying metals are oxidized and removed in the slag, so the slag has a low metal content 
(e.g., 1 to 3 percent) and frequently qualifies as a nonhazardous solid waste. 


7-87 


Because air is introduced into the blast furnace at the tuyeres, blast furnaces are 
operated at positive pressure. The operating temperature at the combustion layer of the charge 
is between 2,200 and 2,600°F (1,200 and 1,400°C), but the temperature of the gases exiting 
the top of the charge material is only between 750 and 950 °F (400 and 500 °C). 

Molten lead collects in the crucible beneath a layer of molten slag. As in a 
reverberatory furnace, the slag inhibits the further oxidation of the molten metal. Lead is 
tapped continuously and slag is tapped intermittently, slightly before it reaches the level of the 
tuyeres. If the tuyeres become blocked with slag, they are manually or automatically 
“punched” to clear the slag. A sight glass on the tuyeres allows the furnace operator to 
monitor the slag level and ensure that they are clear of slag. At most facilities, the slag tap is 
temporarily sealed with a clay plug, which is driven out to begin the flow of slag from the tap 
into a crucible. The slag tap and crucible are enclosed in a hood, which is vented to a control 
device. 


A weir dam and siphon in the furnace are used to remove the lead from beneath 
the slag layer. Lead is tapped from a blast furnace into either a crucible or directly to a 
refining kettle designated as a holding kettle. The lead in the holding kettle is kept molten 
before being pumped to a refining kettle for refining and alloying. The lead tap on a blast 
furnace is hooded and vented to a control device. 

Rotary Furnaces 

As noted above, rotary furnaces (sometimes referred to as rotary reverberatory 
furnaces) (Figure 7-21) are used at only a few recently constructed secondary lead smelters in 
the United States. 236 Rotary furnaces have two advantages over other furnace types: it is 
easier to adjust the relative amount of fluxing agents because the furnaces are operated on a 
batch rather than a continuous basis, and they achieve better mixing of the charge materials 
than do blast or reverberatory furnaces. 


7-88 


Hygiene Hood 



Figure 7-21. Side-view of a Typical Rotary Reverbertory Furnace 
Source: Reference 236. 


7-89 


ERG_IEAD_45 pr» 



















































































































A rotary furnace consists of a refractory-lined steel drum mounted on rollers. 
Variable-speed motors are used to rotate the drum. An oxygen-enriched natural gas or fuel oil 
jet at one end of the furnace heats the charge material and the refractory lining of the drum. 

The connection to the flue is located at the same end as the jet. A sliding door at the end of the 
furnace opposite from the jet allows charging of material to the furnace. Charge materials are 
typically placed in the furnace using a retractable conveyor or charge bucket, although other 
methods are possible. 

Lead-bearing raw materials charged to rotary furnaces include broken battery 
components, flue dust, and drosses. Rotary furnaces can use the same lead-bearing raw 
materials as reverberatory furnaces, but they produce slag that is relatively free of lead, less 
than 2 percent. As a result, a blast furnace is not needed for recovering lead from the slag, 
which can be disposed of as a nonhazardous waste. 

Fluxing agents for rotary furnaces may include iron, silica, soda ash. limestone, 
and coke. The fluxing agents are added to promote the conversion of lead compounds to lead 
metal. Coke is used as a reducing agent rather than as a primary fuel. A typical charge may 
consist of 12 tons (11 Mg) of wet battery scrap, 0.8 tons (0.7 Mg) of soda ash, 0.6 tons 
(0.5 Mg) of coke, and 0.6 tons (0.5 Mg) of iron. This charge will yield approximately 9 tons 
(8 Mg) of lead product. 236 

The lead produced by rotary furnaces is a semi-soft lead with an antimony 
content somewhere between that of lead from reverberatory and blast furnaces. Lead and slag 
are tapped from the furnace at the conclusion of the smelting cycle. Each batch takes 5 to 
12 hours to process, depending on the size of the furnace. Like reverberatory furnaces, rotary 
furnaces are operated at a slight negative pressure. 


. 7-90 


Electric Furnaces 


An electric furnace consists of a large, steel, kettle-shaped container that is 
refractory-lined (Figure 7-22). 236 A cathode extends downward into the container and an anode 
is located in the bottom of the container. Second-run reverberatory furnace slag is charged 
into the top of the furnace. Lead and slag are tapped from the bottom and side of the furnace, 
respectively. A fume hood covering the top of the furnace is vented to a control device. 

In an electric furnace, electric current flows from the cathode to the anode 
through the scrap charge. The electrical resistance of the charge causes the charge to heat up 
and become molten. There is no combustion process involved in an electric furnace. 

There is only one electric furnace in operation in the U.S. secondary lead 
industry. It is used to process second-run reverberatory furnace slag, and it fulfills the same 
role as a blast furnace used in conjunction with a reverberatory furnace. However, the electric 
furnace has two advantages over a blast furnace. First, because there are no combustion gases, 
ventilation requirements are much lower than for blast or reverberatory furnaces, and the 
potential for formation of organics is greatly reduced. Second, the electric furnace is 
extremely reducing, and produces a glass-like, nearly lead-free slag that is nonhazardous. 

7.6.2 Benzene Emissions From Secondary Lead Smelters 

Process emissions (i.e., those emitted from the smelting furnace's main exhaust) 
contain metals, organics (including benzene), HC1, and Cl 2 . Process emissions also contain 
other pollutants, including PM, VOC, CO, and S0 2 . 

Blast furnaces are substantially greater sources of benzene emissions than 
reverberatory or rotary furnaces. Low exhaust temperatures from the charge column (about 
800°F [430°C]) result in the formation of PICs from the organic material in the feed material. 


7-91 



















































































Uncontrolled THC emissions (which correlate closely with organic pollutant emissions) from a 
typical 55,000-tons/yr (50,000 Mg/yr) blast furnace are about 309 tons/yr (280 Mg/yr). 236 

Controlled blast furnace benzene emissions are dependent on the add-on controls 
that are used, which may be anywhere from 80 to 99 percent effective at reducing THC 
emissions. Rotary and reverberatory furnaces have much higher exhaust temperatures than 
blast furnaces, about 1,800 to 2,200°F (980 to 1,200°C), and much lower THC emissions 
because of more complete combustion. Total hydrocarbon emissions from a typical rotary 
furnace (16,500 tons/yr [15,000 Mg/vr] capacity) are about 38 tons/yr (34 Mg/yr). The 
majority of these emissions occur during furnace charging, when the furnace's burner is cut 
back and the temperature is reduced. Emissions drop off sharply when charging is completed 
and the furnace is brought to normal operating temperature. 236 Benzene emissions from 
reverberatory furnaces are even lower than those from rotary furnaces because reverberatory 
furnaces are operated continuously rather than on a batch basis. 

Three test reports from three secondary lead smelters were used to develop 
benzene emission factors. 237 ' 240 All testing was conducted in support of the EPA's Secondary 
Lead National Emission Standards for Hazardous Air Pollutants (NESHAP) program. The 
three facilities tested represent the following process configurations: a rotary smelting furnace 
equipped with a baghouse and S0 2 scrubber; a blast furnace equipped with an afterburner, 
baghouse, and S0 2 scrubber; and a reverberatory and blast furnace with exhaust from each 
furnace combined prior to a single afterburner, baghouse, and S0 2 scrubber. 

Uncontrolled VOC emissions were measured at all three facilities using 
VOST. 241 Nineteen VOC, including benzene, were detected by the VOST. Benzene emissions 
were measured at the blast furnace outlet (before the afterburner) at two facilities, and at the 
rotary furnace outlet at one facility. Total hydrocarbon emissions were measured at both the 
blast furnace and rotary furnace outlets and at the afterburner outlets following the blast 
furnaces. Emission factors for benzene are shown in Table 7-11. 237 * 240 Although benzene 
emissions were not measured after the control device, controlled emission factors were 


7-93 


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estimated using the THC control efficiency for the given process configuration. These 
estimates assume that the control efficiency for benzene was equal to the control efficiency for 
THC. 

7.6.3 Control Technologies for Secondary Lead Smelters 

Controls used to reduce organic emissions from smelting furnaces in the 
secondary lead smelting industry include afterburners on blast furnaces and combined blast and 
reverberatory exhausts. Reverberatory and rotary furnaces have minimal benzene emissions 
because of high exhaust temperatures and turbulence, which promote complete combustion of 
organics. No controls for THC are necessary for these process configurations. 236 

Benzene emissions from blast furnaces are dependent on the type of add-on 
control used. An afterburner operated at 1,300°F (700°C) achieves about 84 percent 
destruction efficiency of THC 236 Facilities with blast and reverberatory furnaces usually 
combine the exhaust streams and vent the combined stream to an afterburner. The higher 
operating temperature of the reverberatory furnace reduces the fuel needs of the afterburner so 
that the afterburner is essentially “idling.” Any temperature increase measured across the 
afterburner is due to the heating value of organic compounds in the blast furnace exhaust. A 
combined reverberatory and blast furnace exhaust stream ducted to an afterburner with an exit 
temperature of 1,700°F (930°C) can achieve 99-percent destruction efficiency for THC. 236 

Additional controls used by secondary lead smelters include baghouses for 
paniculate and metal control, hooding and ventilation to a baghouse for process fugitives, and 
scrubbers for HC1 and S0 2 control. 236 

7.7 IRON AND STEEL FOUNDRIES 

Iron and steel foundries can be defmed as those that produce gray, white, 
ductile, or malleable iron and steel castings. Cast iron and steels are both solid solutions of 


7-95 




iron, carbon, and various alloying materials. Although there are many types of each, the iron 
and steel families can be distinguished by their carbon content. Cast irons typically contain 
2 percent carbon or greater; cast steels usually contain less than 2 percent carbon. 242 

Iron castings are used in almost all types of equipment, including motor 
vehicles, farm machinery, construction machinery, petroleum industry equipment, electrical 
motors, and iron and steel industry equipment. Steel castings are classified on the basis of 
their composition and heat treatment, which determine their end use. Steel casting 
classifications include carbon, low-alloy, general-purpose-structural, heat-resistant, 
corrosion-resistant, and wear-resistant. They are used in motor vehicles, railroad equipment, 
construction machinery, aircraft, agricultural equipment, ore refining machinery, and chemical 
manufacturing equipment. ;4: 


Based on a survey conducted by EPA in support of the iron and steel foundry 
MACT standard development, there were 756 iron and steel foundries in the United States in 
1992. 243 Foundry locations can be correlated with areas of heavy industry and manufacturing 
and, in general, with the iron and steel production industry (Ohio, Pennsylvania, and Indiana). 


Additional information on iron and steel foundries and their locations may be 
obtained from the following trade associations: 

• American Foundrymen's Society, Des Plaines, Illinois; 

• National Foundry Association, Des Plaines, Illinois; 

• Ductile Iron Society, Mountainside, New Jersey; 

• Iron Casting Society, Warrendale, Pennsylvania; and 

• Steel Founders' Society of America, Des Plaines, Illinois. 


/ 


7-96 


7.7.1 


Pisces? Description for Iron and Steel Foundries 


The following four basic operations are performed in all iron and steel 

foundries: 


• Storage and handling of raw materials; 

• Melting of the raw materials; 

• Transfer of the hoi molten metal into molds, and 

• Preparation of the molds to hold the molten metal. 

Other processes present in most, but not all, foundries include: 

• Sand preparation and handling; 

• Mold cooling and shakeout; 

• Casting cleaning, heat treating, and finishing; 

• Coremaking; and 

• Pattern making. 

A generic process flow diagram for iron and steel foundries is given in Figure 7-23. 242 
Figure 7-24 depicts the emission points in a typical iron foundry. 244 

Iron and steel castings are produced in a foundry by injecting or pouring molten 

metal into cavities of a mold made of sand, metal, or ceramic material. Input metal is melted 
by the use of a cupola, an electric arc furnace, or an induction furnace. About 70 percent of 
all iron castings are produced using cupolas, with lesser amounts produced in electric arc and 
induction furnaces. However, the use of electric arc furnaces in iron foundries is increasing. 
Steel foundries rely almost exclusively on electric arc or induction furnaces for melting 
purposes. With either type of foundry, when the poured metal has solidified, the molds are 
separated and the castings removed from the mold flasks on a casting shakeout unit. Abrasive 


7-97 




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Source: Reference 244. 


7-99 


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(shotblasting) cleaning, grinding, and heat treating are performed as necessary. The castings 
are then inspected and shipped to another industry for machining and/or assembly into a final 
product. 242 


In a typical foundry operation, charges to the melting unit are sorted by size and 
density and cleaned (as required) prior to being put in the melter. Charges consist of scrap 
metal, ingot, carbon (coke), and flux. Prepared charge materials are placed in crane buckets, 
weighed, and transferred into the melting furnace or cupola. The charge in a furnace or cupola 
is heated until it reaches a certain temperature and the desired chemistry of the melt has been 
attained. After the desired product is obtained, the molten metal is either poured out of the 
furnace into various sized teeming ladles and then into the molds or it is transferred to holding 
furnaces for later use. 

7.7.2 Benzene Emissions From Iron and Steel Foundries 

Organic compounds are emitted from various process steps in an iron and steel 
foundry, including scrap preparation, the furnace, tapping and treating, mold pouring and 
cooling, casting shakeout, sand cooling, and mold and core production. Benzene may be 
included among other organic compounds emitted from these process steps. Sources of 
organic emissions during these process steps include solvent degreasers used during scrap iron 
charge, coke, and organic binders and organic polymer networks that hold molds and cores 
together to form the castings. 

Data from one testing program at a single gray iron foundry were averaged to 
develop a benzene emission factor (Table 7-12). The emission sources tested were sand cooler 
and belts, casting shakeouts and mixers, and pouring and cooling. Vapors from the sand 
cooler and belts and casting shakeouts and mixers were collected in hoods and ducted to a 
baghouse. Sampling for benzene was performed in accordance with EPA Method 18. All 
sampling was performed at the stack, after the control devices. Benzene emissions from the 
three emission sources were detected; however, because of limited process data availability, a 


7-100 




TABLE 7 12. BENZENE EMISSION FACTOR FOR IRON FOUNDRIES 


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benzene emission factor could only be calculated for the sand cooler and belts, as reflected in 
Table 7-12. 245 - 246 

Benzene from sand coolers and belts and casting shakeouts and mixers may be 
emitted as a result of the heating during mold pouring of the organic binders used to form the 
casting. During mold pouring, the binder materials in the mold are exposed to temperatures 
near 2,550°F (1,400°C). At these temperatures, pyrolysis of the chemical binder may release 
organic chemicals which become trapped in the sand inside the casting. During shakeout and 
sand cooling, the sand is exposed to the atmosphere and these organic chemicals may be 
released. 

7.7.3 Control Technologies for Iron and Steel Foundries 244 

Scrap preparation with heat or solvent degreasers will emit organic compounds. 
Catalytic incinerators and afterburners can control about 95 percent of organic emissions. 

Emissions released from melting furnaces include organic compounds. The 
highest concentrations of furnace emissions occur when furnace doors are open during 
charging, backcharging, alloying, slag removal, and tapping operations. These emissions can 
escape into the furnace building or can be collected and vented through roof openings. 
Emission controls for melting and refining operations involve venting furnace gases and fumes 
directly to a control device. Canopy hoods or special hoods near furnace doors and tapping 
points capture emissions and route them to emission control systems. 

A cupola furnace typically has an afterburner, which achieves up to 95 percent 
efficiency. The afterburner is located in the furnace stack to oxidize CO and bum organic 
fumes, tars, and oils. Reducing these contaminants protects the particulate control device from 
possible plugging and explosion. Toxic emissions from cupolas include both organic and 
inorganic materials. Cupolas produce the most toxic emissions compared to other melting 
equipment. During melting in an electric arc furnace, hydrocarbons are emitted from 


7-102 



vaporization and incomplete combustion of any oil remaining on the scrap iron charge. 

Electric induction furnaces emit negligible amounts of hydrocarbon emissions, and are 
typically uncontrolled except during charging and pouring operations. 

Organic emissions are generated during the refining of molten iron before 
pouring and from the mold and core materials during pouring. Toxic emissions of halogenated 
and aromatic hydrocarbons are released in the refining process. Emissions from pouring 
normally are captured by a collection system and vented, either controlled or uncontrolled, to 
the atmosphere. Emissions continue as the molds cool. 

Organics are emitted in mold and core production operations from core baking 

and mold drying. Afterburners and catalytic incinerators can be used to control organics 
emissions. 


In addition to organic binders, molds and cores may be held together in the 
desired shape by means of a cross-linked organic polymer network. This network of polymers 
undergoes thermal decomposition when exposed to the very high temperatures of casting, 
typically 2,550°F (1,400°C). At these temperatures it is likely that pyrolysis of the chemical 
binder will produce a complex of free radicals that will recombine to form a wide range of 
chemical compounds having widely differing concentrations. 

There are many different types of resins currently in use, with diverse and toxic 
compositions. No data are available for determining the toxic compounds in a particular resin 
that are emitted to the atmosphere and to what extent these emissions occur. 

7.8 PORTLAND CEMENT PRODUCTION 

Most of the hydraulic cement produced in the United States is Portland 
cement-a cementitious, crystalline compound composed of metallic oxides. The end-product 
cement, in its fused state, is referred to as “clinker.” Raw materials used in the process can be 


7-103 


calcium carbonate- and aluminum-containing limestone, iron, silicon oxides, shale, clay, and 
sand. 247 As of December 1990, there were 112 Portland cement plants in the United States 
operating 213 kilns with a total annual clinker capacity of 80 million tons (73.7 million Mg). 
The kiln population included 80 wet process kilns and 133 dry process kilns. 247 U.S. Portland 
cement plants are listed in Table 7-13 . 

7.8.1 Process Description for the Portland Cement Industry 

In Portland cement production, most raw materials typically are quarried on site 
and transferred by conveyor to crushers and raw mills. After the raw materials are reduced to 
the desired particle size, they are blended and fed to a large rotary kiln. The feed enters the 
kiln at the elevated end, and the burner is located at the opposite end. The raw materials are 
then changed into cementitious oxides of metal by a countercurrent heat exchange process. 

The materials are continuously and slowly moved to the low end by the rotation of the kiln 
while being heated to high temperatures (2,700°F [1,482°C]) by direct firing (Stream 3 in 
Figure 7-25). In this stage, chemical reactions occur, and a rock-like substance called 
“clinker” is formed. This clinker is then cooled, crushed, and blended with gypsum to 
produce Portland cement. 247 The cement is then either bagged or bulk-loaded and transported 


Cement may be made via a wet or a dry process. Many older kilns use the wet 
process. In the past, wet grinding and mixing technologies provided more uniform and 
consistent material mixing, resulting in a higher quality clinker. Dry process technologies 
have improved, however, to the point that all of the new kilns since 1975 use the dry 
process. 249 In the wet process, water is added to the mill while the raw materials are being 
ground. The resulting slurry is fed to the kiln. In the dry process, raw materials are also 
ground finely in a mill, but no water is added and the feed enters the kiln in a dry state. 

More fuel is required for the wet process than the dry process to evaporate the 
water from the feed. However, for either the wet or dry process, Portland cement production 
is fuel-intensive. The fuel burned in the kiln may be natural gas, oil, or coal. Many cement 


7-104 



TABLE 7-13. SUMMARY OF PORTLAND CEMENT 
PLANT CAPACITY INFORMATION 


Location 

Number of Plants 
(kilns) 

Capacity 

10 3 tons/yr (10 3 Mg/yr) 

Alabama 

5(6) 

4,260 (3,873) 

Alaska 

1(0)* 

0(0) 

Arizona 

2(7) 

1,770(1,609) 

Arkansas 

2(5) 

1,314(1,195) 

California 

12 (20) 

10,392 (9,447) 

Colorado 

3(5) 

1,804 (1,640) 

Florida 

6(8) 

3,363 (3,057) 

Georgia 

2(4) 

1,378 (1,253) 

Hawaii 

KD 

263 (239) 

Idaho 

1 (2) 

210(191) 

Illinois 

4(8) 

2,585 (2,350) 

Indiana 

4(8) 

2,830 (2,573) 

Iowa 

4(7) 

2,806 (2,551) 

Kansas 

4(11) 

1,888 (1,716) 

Kentucky 

1 (1) 

724 (658) 

Maine 

1 (1) 

455 (414) 

Maryland 

3(7) 

1,860 (1,691) 

Michigan 

5(9) 

4.898 (4.453) 

Mississippi 

KD 

504 (458) 

Missouri 

5(7) 

4,677 (4,252) 

Montana 

2(2) 

592 (538) 

Nebraska 

1(2) 

961 (874) 

Nevada 

1(2) 

415 (377) 

New Mexico 

1(2) 

494 (449) 

New York 

4(5) 

3,097 (2,815) 

Ohio 

£15) 

1,703 (1,548) 


7-105 


(continued) 







TABLE 7-13. CONTINUED 


Location 

Number of Plants 
(kilns) 

Capacity 

10 3 tons/yr (10 3 Mg/yr) 

Oklahoma 

3(7) 

1,887 (1,715) 

Oregon 

KD 

480 (436) 

Pennsylvania 

11 (24) 

6,643 (6,039) 

South Carolina 

3(7) 

2,579 (2,345) 

South Dakota 


766 (696) 

Tennessee 

2(3) 

1,050 (955) 

Texas 

12 (20) 

8,587 (7,806) 

Utah 

2(3) 

928 (844) 

Virginia 

1(5) 

1,117 (1,015) 

Washington 

i (i) 

473 (430) 

West Virginia 

1 (3) 

822 (747) ‘ 

Wyoming 

KD 

461 (419) 


Source: Reference 247. 

a Grinding plant only. 


7-106 






plants bum coal, but supplemental fuels such as waste solvents, chipped rubber, shredded 
municipal garbage, and coke have been used in recent years. 247 A major trend in the industry 
is the increased use of waste fuels. In 1989, 33 plants in the United States and Canada 
reported using waste fuels; the number increased to 55 plants in 1990. 247 

The increased use of hazardous waste-derived fuels (HWDFs) for the kilns is 
attributed to lower cost and increased availability. As waste generators reduce or eliminate 
solvents from their waste steams, the streams contain more sludge and solids. As a result, two 
new hazardous waste fueling methods have emerged at cement kilns. The first method pumps 
solids (either slurried with liquids or dried and ground) into the hot end of the kiln. The 
second method (patented by cement kiln processor and fuel blender Cadence, Inc.) introduces 
containers of solid waste into the calcining zone of the kiln. 250 

The kiln system for the manufacture of Portland cement by dry process with 
preheater is shown in Figure 7-25. The raw material enters a four-stage suspension preheater, 
where hot gases from the kiln heat the raw feed and provide about 40-percent calcination 
(Stream 1) before the feed enters the kiln. Some installations include a precalcining furnace 
(Stream 2), which provides about 85 percent calcination before the feed enters the kiln. 247 

7.8.2 Benzene Emissions from the Portland Cement Industry and Regulatory Analysis 

The raw materials used by some facilities may contain organic compounds, 
which become a source of benzene emissions during the heating step. However, fuel 
combustion to heat the kiln is believed to be the greater source of benzene emissions. As 
shown in Table 7-14, benzene is emitted when either fossil fuels or HWDFs are combusted in 
the kiln. 247 249 - 251 

Facilities that bum HWDF are subject to the Boilers and Industrial Furnaces 
(BIF) rule promulgated February 21, 1991, under the Resource Conservation and Recovery 

Act (RCRA). The BIF rule requires that a facility that bums hazardous waste demonstrate a 


7-107 




7-108 


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TABLE 7-14. SUMMARY OF EMISSION FACTORS FOR THE PORTLAND CEMENT INDUSTRY 


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99.99 percent destruction efficiency for principal organic hazardous constituents in the waste 
stream. To guard against products of incomplete combustion, the BIF rule limits CO levels in 
the kiln and or total hydrocarbon levels in stack gases. 250,251 In addition, a NESHAP for 
control of HAPs from Portland Cement Kilns is under development. 

Table 7-14 presents a summary of benzene emission factors for wet process 
cement kilns controlled with electrostatic precipitators burning HWDF in conjunction with 

other fuels. 

7.9 HOT-MIX ASPHALT PRODUCTION 

In 1994, there were approximately 3,600 asphalt hot-mix plants. 252 
Approximately 40 percent of companies that operate hot-mix plants operate a single plant. 
Because plants must be located near the job site, plants are concentrated in areas where the 
highway and road network is concentrated. 2 ^ Additional information on the locations of 
individual hot-mix asphalt facilities can be obtained by contacting the National Asphalt 
Pavement Association in College Park, Maryland. 

7.9.1 Process Description 

There are three types of hot-mix asphalt plants operating in the United States: 
batch-mix, continuous-mix, and dmm-mix. At batch-mix and continuous-mix plants, the 
aggregate drying process is performed separately from the mixing of aggregate with asphalt 

cement. Drum-mix plants combine these two processes. Production capacities for all three 
types of plants range from 40 to 600 tons (36 to 544 Mg) of hot mix per hour. Almost all 
plants in use are of either the batch-mix or the drum-mix types. Less than half a percent of 
operating hot-mix asphalt plants are of the continuous-mix variety. 79 Over 80 percent of all 
hot-mix asphalt production plants are mobile. 245 


7-110 



In the production of hot-mix asphalt (also referred to as asphalt concrete), 
aggregate is heated to eliminate moisture and then mixed with hot asphalt cement. The 
resulting hot mixture is pliable and able to be compacted and smoothed. When the hot-mix 
asphalt cools and hardens, it provides a waterproof and durable pavement for roads, 

driveways, parking lots, and runways. 

Aggregate, the basic raw material of hot-mix asphalt, consists of any hard, inert 
mineral material, usually gravel, sand, and mineral filler. Aggregate typically comprises 
between 90 and 95 percent by weight of the asphalt mixture. Because aggregate provides most 
of the load-bearing properties of a pavement, the performance of the pavement depends on 
selection of the proper aggregate. 

Asphalt cement is used as the binding agent for aggregate. It prevents 
moisture from penetrating the aggregate, and it acts as a cushioning agent. Typically, asphalt 
cement constitutes 4 to 0 percent Dy weignt ot a not-mix aspnait mixture. 15 ' 

As with the asphalt flux used to produce asphalt roofing products, asphalt 
cement is obtained from the distillation of crude oil. It is classified into grades under one of 
several classification schemes. The most commonly used scheme classifies asphalt cement 
based on its viscosity at 140°F (60°C). The more viscous the asphalt cement, the higher its 
numerical rating. An asphalt cement of grade AC-40 is considered a hard asphalt (i.e., a 
viscosity of 4,000 grams per centimeter per second [g/cm-s or poises]), whereas an asphalt 
cement of grade AC-2.5 is considered a soft asphalt (i.e., a viscosity of 250 g/cm-s [poises]). 

Several western States use a second classification scheme that measures viscosity 
of the asphalt cement after a standard simulated aging period. This simulated aging period 
consists of exposure to a temperature of 325°F (163 °C) for 5 hours. Viscosity is measured at 
140°F (60 °C), with grades ranging from AR-1000 for a soft asphalt cement (1000 g/cm-s 
[poises]) to AR-16000 for a hard asphalt cement (16,000 g/cm-s [poises]). 


7-111 



A third classification scheme is based on the penetration allowed by the asphalt 
cement. Grade designation 40 to 50 means that a needle with a weight attached will penetrate 
the asphalt cement between 40 and 50 tenths of a millimeter under standard test conditions. 
The hard asphalt cements have penetration ratings of 40 to 50, whereas the soft grades have 
penetration ratings of 200 to 300. 253 

The asphalt cement grade selected for different hot-mix asphalts depends on the 
type of pavement climate, and type and amount of traffic expected. Generally, asphalt 
pavement bearing heavy traffic in warm climates would require a harder asphalt cement than 
pavement subject to either light traffic or cold climate conditions. 

Another material that is used to a greater extent in the production of new or 
virgin hot-mix asphalt is recycled asphalt pavement (RAP), which is pavement material that 
has been removed from existing roadways. This RAP material is now used by virtually all 
companies m their hot-mix asphalt mixtures. The Surface Transportation Assistance Act of 
1982 encourages recycling by providing a 5-percent increase in Federal funds to State agencies 
that recycle asphalt pavement. Rarely does the RAP comprise more than 60 percent by weight 
of the new asphalt mixture. Twenty-five percent RAP is typical in batch plants, whereas 40 to 
50 percent RAP mixtures are typical in drum-mix plants. 253 

Rejuvenating agents are sometimes added to hot-mix asphalts where they are 
blended with RAP, which brings the weathered and aged asphalt cement in the recycled 
mixture up to the specifications of a new asphalt mixture. Usually, a soft asphalt cement, a 
specially prepared high-viscosity oil, or a hard asphalt cement blended with a low-viscosity oil 
are used as rejuvenating agents. The amount of rejuvenating agent added depends on the 
properties of the RAP and on the specifications for the hot-mix asphalt product. 

The primary processes of a typical batch-mix hot-mix asphalt facility are 
illustrated in Figure 7-26. 252 Aggregate of various sizes is stockpiled at the plant for easy 
access. The moisture content of the stockpiled aggregate usually ranges from 3 to 5 percent. 


7-112 





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7-113 


Figure 7-26. General Process Flow Diagram for Batch Mix Asphalt Paving Plants 














































































































The moisture content of recycled hot-mix asphalt typically ranges from 2 to 3 percent. The 
different sizes of aggregate are typically transported by front-end loader to separate cold feed 
bins and metered onto a feeder conveyor belt through gates at thie bottom of the bins. The 
aggregate is screened before it is fed to the dryer to keep oversize material out of the mix. 

The screened aggregate is then fed to a rotating dryer with a burner at its lower 
(discharge) end that is fired with fuel oil, natural gas, or propane. The dryer removes moisture 
from the agg r egate and heats the aggregate to the proper mix temperature. Inside the dryer are 
longitudinal flights (metal slats) that lift and tumble the aggregate, causing a curtain of material 
to be exposed to the heated gas stream. This curtain of material provides greater heat transfer 
to the aggregate than would occur if the aggregate tumbled along the bottom of the drum 
towards the discharge end. Aggregate temperature at the discharge end of the dryer is about 
300 °F (149°C). The amount of aggregate that a dryer can heat depends on the size of the 
drum, the size of the burner, and the moisture content of the aggregate. As the amount of 
moisture to be removed from the aggregate increases, the effective production capacity of the 
dryer decreases. 

Vibrating screens segregate the heated aggregate into bins according to size. A 
weigh hopper meters the desired amount of the various sizes of aggregate into a pugmill mixer. 
The pugmill typically mixes the aggregate for approximately 15 seconds before hot asphalt 
cement from a heated tank is sprayed into the pugmill. The pugmill thoroughly mixes the 
aggregate and hot asphalt cement for 25 to 60 seconds. The finished hot-mix asphalt is either 
directly loaded into trucks or held in insulated and/or heated storage silos. Depending on the 
production specifications, the temperature of the hot-mix asphalt product mix can range from 
225 to 350°F (107 to 177°C) at the end of the production process. 

When a hot mix containing RAP is produced, the aggregate is superheated 
(compared to totally virgin hot-mix asphalt production) to about 600°F (315°C) to ensure 
sufficient heat transfer to the RAP when it is mixed with the virgin materials. The RAP 


7-114 


material may be added either to the pugmill mixer or at the discharge end of the dryer. Rarely 
is more than 30 percent RAP used in batch plants for the production of hot-mix asphalt. 


Continuous-mix plants are very similar in configuration to batch plants. 
Continuous-mix plants have smaller hot bins (for holding the heated aggregate) than do batch 
plants. Little surge capacity is required of these bins because the aggregate is continuously 
metered and transported to the mixer inlet by a conveyor belt. Asphalt cement is continuously 
added to the aggregate at the inlet of the mixer. The aggregate and asphalt cement are mixed 
by the action of rotating paddles as they are conveyed through the mixer. An adjustable dam at 
the outlet end of the mixer regulates the mixing time and also provides some surge capacity. 
The finished mix is transported by a conveyor belt to either a storage silo or surge bin. 253 


Drum-mix plants dry the aggregate and mix it with the asphalt cement in the 
same drum, eliminating the need for the extra conveyor belt, hot bins and screens, weigh 

hopper, and pugmill of batch-mix plants. The drum of a drum-mix plant is much like the drye: 

of a batch plant, but it typically has more flights than do batch dryers to increase veiling of the 
aggregate and to improve overall heat transfer. The burner in a drum-mix plant emits a much 
bushier flame than does the burner in a batch plant. The bushier flame is designed to provide 
earlier and greater exposure of the virgin aggregate to the heat of the flame. This design also 
protects the asphalt cement, which is injected away from the direct heat of the flame. 253 


Initially, drum-mix plants were designed to be parallel flow as depicted in 
Figure 7-27. 252 Recently, the counterflow drum-mix plant design shown in Figure 7-28 has 
become popular. 79 The parallel flow drum-mix process is a continuous mixing type process 
using proportioning cold-feed controls for the process materials. Aggregate, which has been 
proportioned by gradations, is introduced to the drum at the burner end. As the drum rotates, 
the aggregate as well as the combustion products move toward the other end of the drum in 
parallel. Liquid asphalt cement flow is controlled by a variable flow pump that is 
electronically linked to the virgin aggregate and RAP weigh scales. The asphalt cement is 


7-115 




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Figure 7-28. General Process Flow Diagram for Counter Flow Drum Mix Asphalt Paving Plants 













































































































introduced in the mixing zone midway down the drum in a lower temperature zone, along with 
any RAP and PM from the collectors. The mixture is discharged at the end of the drum and 
conveyed to a surge bin or storage silos. The exhaust gases also exit the end of the drum and 
pass on to the collection system. 79 

In the counterflow drum-mix type plant, the material flow in the drum is 
opposite or counterflow to the direction of exhaust gases. In addition, the liquid asphalt 
cement mixing zone is located behind the burner flame zone so as to keep the materials from 
direct contact with hot exhaust gases. Liquid asphalt cement flow is still controlled by a 
variable flow pump and is injected into the mixing zone along with any RAP and PM from 
primary and secondary collectors. 79 

Parallel-flow drum mixers have an advantage in that mixing in the discharge end 
of the drum captures a substantial portion of the aggregate dust, thereby lowering the load on 
the downstream collection equipment. For this reason, most parallel flow drum mixers are 
followed only by primary collection equipment (usually a baghouse or venturi scrubber). 
However, because the mixing of aggregate and liquid asphalt cement occurs in the hot 
combustion product flow, organic emissions (gaseous and liquid aerosol) from parallel-flow 
drum mixers may be greater than in other processes. 79 

On the other hand, because the liquid asphalt cement, virgin aggregate, and 
RAP are mixed in a zone removed from the exhaust gas stream, counterflow drum-mix plants 
will likely have organic emissions (gaseous and liquid aerosol) that are lower than those from 
parallel-flow drum-mix plants. A counterflow drum-mix plant can normally process RAP at 
ratios up to 50 percent with little or no observed effect on emissions. Today's counterflow 
drum-mix plants are designed for improved thermal efficiencies. 79 

Of the 3,600 active hot-mix asphalt plants in the United States, approximately 
2,300 are batch-mix plants, 1,000 are parallel-flow drum-mix plants, and 300 are counterflow 
drum-mix plants. About 85 percent of plants being built today are of the counterflow 


7-118 


drum-mix design; batch-mix plants and parallel-flow drum-mix plants account for 10 and 
5 percent, respectively. 79 

One major advantage of both types of drum-mix plants is that they can produce 
material containing higher percentages of RAP than batch-mix plants can produce. The use of 
RAP significantly reduces the amount of new (virgin) rock and asphalt cement needed to 
produce hot-mix asphalt. With the greater veiling of aggregate, drum-mix plants are more 
efficient than batch-mix plants at transferring heat and achieving proper mixing of recycled 
asphalt and virgin materials. 253 

7.9.2 Benzene Emissions from the Hot-Mix Asphalt Production 

Emissions of benzene from hot-mix asphalt plants occur from the aggregate 
rotary dryers and the asphalt heaters (due to fuel combustion). In Figure 7-26, the emission 
point for the rotary dryer is indicated by SCC 3-05-002-01, and the emission pomt for the 
heater is indicated by SCC 3-05-002-06, -07, -08, and -09. Note that most of the emission 
points in Figures 7-26 and 7-27 are sources of paniculate matter. Most plants employ some 
form of mechanical collection, typically cyclones, to collect aggregate panicle emissions from 
the rotary dryers. However, these cyclones would have a minimal collection efficiency for 
benzene. 

Other types of controls installed at asphalt hot-mix plants, primarily to control 
PM emissions, include wet scrubbers or baghouses. 253 These controls are expected to have 
some effect on reducing benzene emissions; however, the control efficiencies are not known. 

Table 7-15 presents four emission factors for the rotary dryer at a hot-mix 
asphalt plant. 3,254 " 263 The factors range from 1.41x10^ lb/ton (7.04xl0' 5 kg/Mg) to 
1.95x10' 5 lb/ton (9.75x1 O' 6 kg/Mg) and differ in the type of fuel burned to heat the dryer 
(LPG, oil, natural gas, or diesel) and the type of control device used (cyclone, baghouse, wet 
scrubber, or uncontrolled). Table 7-15 also presents one emission factor for an 


7-119 



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7-120 


* Emission factors are in lb (kg) of benzene emitted per ton (Mg) of hot-mix asphalt produced. 












uncontrolled asphalt heater fired with diesel fuel. The source tests from which these emission 
factors were derived all use CARB Method 401 for sampling. 

No regulations were identified that require control of benzene emissions at hot 
mix asphalt plants. 

7.10 OPEN BURNING OF BIOMASS, SCRAP TIRES, AND AGRICULTURAL 

PLASTIC FILM 

Open burning involves the burning of various materials in open drums or 
baskets, in fields or yards, and in large open drums or pits. Materials commonly disposed of 
in this manner include municipal waste, auto body components, landscape refuse, agricultural 
field refuse, wood refuse, bulky industrial refuse, and leaves. This section describes the open 
burning of biomass, scrap tires, and agricultural plastic film, and their associated benzene 
emissions. 

7.10.1 Biomass Burning 

Fires are known to produce respirable PM and toxic substances. Concern has 
even been voiced regarding the effect of emissions from biomass burning on climate change. 264 
Burning wood, leaves, and vegetation can be a source of benzene emissions. In this document, 
the burning of any wood, leaves, and vegetation is categorized as biomass burning, and 
includes yard waste burning, land clearing/buming and slash burning, and forest 
fires/prescribed burning. 265 

Part of the complexity of fires as a source of emissions results from the complex 
chemical composition of the fuel source. Different woods and vegetation are composed of 
varying amounts of cellulose, lignin, and extractives such as tannins, and other polyphenolics, 
oils, fats, resins, waxes, and starches. 266 General fuel type categories in the National Fire- 
Danger Rating (NFDR) System include grasses, brush, timber, and slash (residue that remains 
on a site after timber harvesting). 266 The flammability of these fuel types depends upon plant 


7-121 



species, moisture content, whether the plant is alive or dead at the time of burning, weather, 
and seasonal variations. 

Pollutants from the combustion of biomass include CO, NO x , sulfur oxides 
(SO x ), oxidants, polycyclic organic matter (POM), hydrocarbons, and PM. The large number 
of combustion products is due, in part, to the diversity of combustion processes occurring 
simultaneously within a fire-flaming, smoldering, and glowing combustion. These processes 
are distinct combustion processes that involve different chemical reactions that affect when and 
what pollutants will be emitted during burning. 266 

Emission factor models (based on field and laboratory data) have been 
developed by the U.S. Forest Service. These models incorporate variables such as fuel type 
and combustion types (flaming or smoldering). Because ratios of toxic air substances are 
correlated with the release of other primary PICs (such as CO), the models correlate benzene 
witn CO emissions. 2 " Tnese emission factor models were used to develop emission factors for 
the biomass burning sub-categories described in the following sections. 265 

Because of the potential variety in the fuel source and the limited availability of 

emission factors to match all possible fuel sources, emissions estimates may not necessarily 

« 

represent the combustion practices occurrmg at every location in the United States. Therefore, 
localized practices of such parameters as type of wood being burned and control strategies 
should be carefully compared. 265 

Yard Waste Burning 

Yard waste burning is the open burning of such materials as landscape refuse, 
wood refuse, and leaves in urban, suburban, and residential areas. 265 Yard waste is often 
burned in open drums, piles, or baskets located in yards or fields. Ground-level open burning 
emissions are affected by many variables, including wind, ambient temperature, composition 
and moisture content of the material burned, and compactness of the pile. It should be noted 


7-122 



that this type of outdoor burning has been banned in certain areas of the United States, thereby 
reducing emissions from this subcategory. 265 - 267 An emission factor for yard waste is shown in 
Table 7-16. 265 - 266 

Land Clearing and Slash Burning 

This subcategory includes the burning of organic refuse (field crops, wood, and 
leaves) in fields (agricultural burning) and wooded areas (slash burning) in order to clear the 
land. Burning as part of commercial land clearing often requires a permit. 205 Emissions from 
organic agricultural refuse burning are dependent primarily on the moisture content of the 
refuse and, in the case of field crops, on whether the refuse is burned in a headfire or a 
backfire. 26 ' Other variables, such as fuel loading (how much refuse material is burned per unit 
of land area) and how the refuse is arranged (piles, rows, or spread out), are also important in 
certain instances. 267 Emission factors for land clearing/buming and slash burning are shown in 
Table 7-lb 265 - 266 

Forest Fires/Prescribed Burning 

A forest fire (or wildfire) is a large-scale natural combustion process that 
consumes various ages, sizes, and types of outdoor vegetation. 268 The size, intensity, and even 
occurrence of a forest fire depend on such variables as meteorological conditions, the species 
and moisture content of vegetation involved, and the weight of consumable fuel per acre (fuel 
loading). 268 


Prescribed or broadcast burning is the intentional burning of forest acres as part 
of forest management practices to achieve specific wildland management objectives. 

Controlled burning can be used to reduce fire hazard, encourage wildlife habitat, control 
insects, and enhance the vigor of the ecosystem. 266 Prescribed burning occurs thousands of 
times annually in the United States, and individual fires vary in size from a fraction of an acre 


7-123 


TABLE 7-16. SUMMARY OF BENZENE EMISSION FACTORS FOR BIOMASS BURNING 


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7-124 




























to several thousand acres. Prescribed fire use is often seasonal, which can greatly affect the 
quantity of emissions produced. 266 

HAP emission factors for forest fires and prescribed burning were developed 
using the same basic approach for yard waste and land clearing burning, with an additional 
step to further classify fuel types into woody fuels (branches, logs, stumps, and limbs), live 
vegetation, and duff (layers of partially decomposed organic matter). 265 In addition to the fuel 
type, the methodology was altered to account for different phases of burning, namely, flaming 
and smoldering. 265 The resulting emission factors are shown in Table 7-17. 

7.10.2 Tire Burning 

Approximately 240 million vehicle tires are discarded annually. 269 Although 
viable methods for recycling exist, less than 25 percent of discarded tires are recycled; the 
remammg 175 million are discarded in landfills, stockpiles, or illegal dumps. 2 '"" Although it is 
illegal in many states to dispose of tires using open burning, fires often occur at tire stockpiles 
and through illegal burning activities. 267 These fires generate a huge amount of heat and are 
difficult to extinguish (some tire fires continue for months). 

Table 7-18 contains benzene emission factors for chunk tires and shredded 
tires. 267 When estimating emissions from an accidental tire fire, it should be kept in mind that 
emissions from burning tires are generally dependent on the bum rate of the tire. A greater 
potential for emissions exists at lower bum rates, such as when a tire is smoldering rather than 
burning out of control. 267 The fact that the shredded tires have a lower bum rate indicates that 
the gaps between tire materials provide the major avenue of oxygen transport. Oxygen 
transport appears to be a major, if not the controlling mechanism for sustaining the combustion 
process. 


7-125 



TABLE 7-17. SUMMARY OE BENZENE EMISSION FACTORS FOR BIOMASS BURNING BY FUEL TYPE 


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7-126 


Live Uncontrolled 1.48 

vegetation _ ( 7.4 x 10 *) 












TABLE 7-17. COMTINUED 


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7-127 



















SNZENE EMISSION FACTORS FOR OPEN BURNING OF TIRES 


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7-128 

















7.10.3 


Agricultural Plastic Film Burning 


Agricultural plastic film is plastic film that has been used for ground moisture 
and weed control. The open burning of large quantities of plastic film commonly coincides 
with the burning of field crops. The plastic film may also be gathered into large piles and 
burned, with or without forced air (an air curtain). 267 

Emissions from burning agricultural plastic film are dependent on whether the 
film is new or has been exposed to vegetation and possibly pesticides. Table 7-19 presents 
emission factors for benzene emissions from burning new and used plastic film in piles with 
and without forced air (i.e., air is forced through the pile to simulate an air curtain). 267 


7-129 




TABLE 7-19. SUMMARY OF BENZENE EMISSION FAC TORS FOR OPEN BURNING 

OF AGRICULTURAL PLASTIC FILM 


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7-130 
























SECTION 8.0 

BENZENE EMISSIONS FROM MOBILE SOURCES 

This section quantifies benzene as one component of mobile source hydrocarbon 
emissions. These emissions occur from mobile sources as evaporative emissions from 
carburetors, fuel tanks, and crankcases, and as a result of combustion. 

Benzene is not added to vehicle fuels such as gasoline or diesel, but is formed 
during their manufacture, either through catalytic reforming or steam cracking. Most vehicle 
fuel is p T ‘"'ce? c ed usirg catalytic reforming In catalytic reforming, benzene is produced during 
the reaction that increases the octane rating of the naphtha fraction of the crude oil used as 
feedstock. Gasoline produced using this process is approximately 0.90 percent benzene (by 
weight). 158 (See Section 4.1 for an expanded discussion of catalytic reforming.) 

The other vehicle fuel manufacturing process, the use of steam cracking of 

naphtha feedstock to obtain ethylene, yields gasoline with a higher benzene content-20 to 
50 percent. This fuel is blended with other fuels, before it is sold, in order to comply with the 
limited maximum concentration of 1.3 percent (by volume). However, steam cracking is 
considered a minor source of vehicle fuel. (Refer to Section 4.3 for an expanded discussion of 
pyrolysis gasoline and ethylene plants.) 

Diesel fuel, on the other hand, is produced by hydrocracking of the gas oil 
fraction of crude, and contains relatively insignificant amounts of benzene. 


8-1 


Benzene is emitted in vehicle exhaust as unbumed fuel and as a product of 
combustion. Higher-molecular-weight aromatics in the fuel, such as ethylbenzene and toluene, 
can be converted to benzene as products of combustion, accounting for approximately 70 to 
80 percent of the benzene in vehicle exhaust. 

The fraction of benzene in the exhaust varies depending on vehicle type, fuel 
type, and control technology, but is generally between 3 to 5 percent by weight of the exhaust. 
The fraction of benzene in the evaporative emissions also depends on control technology and 
fuel composition, and is generally 1 percent of a vehicle's evaporative emissions. 

8.1 ON-ROAD MOBILE SOURCES 


Results of recent work by the Office of Mobile Sources (OMS) on toxic 
emissions from on-road motor vehicles are presented in the 1993 report Motor Vehicle-Related 

Air Toxics Study (MVATS). 20 This report was prepared in response to Section 202(I)(l) of the 

1990 amended CAA, which directs EPA to complete a study of the need for, and feasibility of, 
controlling emissions of toxic air pollutants that are unregulated under the Act and are 
associated with motor vehicles and motor vehicle fuels. The report presents composite 

emission factors for several toxic air pollutants, including benzene. 


The emission factors presented in the MV ATS were developed using currently 
available emissions data in a modified version of the OMS's MOBILE4.1 emissions model 
(designated MOBTOX) to estimate toxic emissions as a fraction of total organic gas (TOG) 
emissions. TOG includes all hydrocarbons as well as aldehydes, alcohols, and other 
oxygenated compounds. All exhaust mass fractions were calculated on a vehicle-by-vehicle 
basis for six vehicle types: light-duty gasoline vehicles, light-duty gasoline trucks, heavy-duty 
gasoline trucks, light-duty diesel vehicles, light-duty diesel trucks, and heavy-duty diesel 
trucks. 


8-2 


OMS assumed that light-duty gas and diesel trucks have the same mass fractions 
as light-duty gas and diesel vehicles, respectively. In developing mass fractions for light-duty 
gas vehicles and trucks, four different catalytic controls and two different fuel systems 
(carbureted or fuel injection) were considered. Mass fractions for heavy-duty gas vehicles 
were developed for carbureted fuel systems with either no emission controls or a three-way 
catalyst. These mass fractions were applied to TOG emission factors developed to calculate in- 
use benzene emission factors. These in-use factors take into consideration evaporative and 
exhaust emissions as well as the effects of vehicle age. 

A number of important assumptions were made in the development of these 
on-road benzene emission factors, namely: 

1. The increase in emissions due to vehicle deterioration with increased 
mileage is proportional to the increase in TOG; 

2. Toxics fractions remain constant with ambient temperature changes; and 

3. The fractions are adequate to use for the excess hydrocarbons that come 
from malfunction and tampering/misfueling. 

It should be noted that, in specific situations, EPA mobile methods may over or underestimate 
actual emissions. 

The benzene emission factors by vehicle class in grams of benzene emitted per 
mile driven are shown in Table 8-1. 270 The OMS also performed multiple runs of the 
MOBTOX program to derive a pollutant-specific, composite emission factor that represented 
all vehicle classes, based on the percent of total vehicle miles traveled (VMT) attributable to 
each vehicle class. 20 

For traditional gasoline, benzene is typically responsible for 70 to 75 percent of 
the aggregated toxic emissions. Most of this is associated with engine combustion exhaust. 


8-3 


TABLE 8-1. BENZENE EMISSION FACTORS FOR 1990 
TAKING INTO CONSIDERATION VEHICLE AGING (g/mi) 


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8-4 














Oxygenated fuels emit less benzene than traditional gasoline mixes but more 
than diesel fuel. With the introduction of alternative fuels such as methanol blends, 
compressed natural gas (CNG), and liquified petroleum gas (LPG), formaldehyde is the 
dominant toxic emission, accounting for 80 to 90 percent of aggregated toxic emissions. 272 
Reductions in benzene emissions associated with the use of methanol fuels is dependent upon 
the methanol content of the fuel. For instance, benzene emissions for M10 (10 percent 
methanol and 90 percent unleaded gasoline) are reduced by 20 percent compared with 
traditional fuel, and for M85 (85 percent methanol and 15 percent unleaded gasoline) the 
reduction is 84 percent (SAE1992). Ml00 (100 percent methanol), ethanol, LPG, and CNG 
emit minimal amounts of benzene. 273 Furthermore, because both LPG and CNG require closed 
delivery systems, evaporative emissions are assumed to be zero. 

8.2 OFF-ROAD MOBILE SOURCES 

ror on-roaa mooile sources, EPA prepared me report Nonroad Engine 
Vehicle Emission Study (NEVES), 274 which presents emission factors for 79 equipment types, 
ranging from small equipment such as lawn mowers and chain saws to large agricultural, 
industrial, and construction machinery (see Table 8-2). The equipment types were evaluated 
based on three engine designs: two-stroke gasoline, four-stroke gasoline, and diesel. Sources 
for the data include earlier EPA studies and testing and new information on tailpipe exhaust 
and crankcase emissions supplied by the engine manufacturers. For test data on new engines, 
OMS made adjustments to better represent in-use equipment emissions taking into 
consideration evaporative emissions and increases in emissions due to engine deterioration 
associated with increased equipment age; therefore, new engine data underestimate in-use 
emissions. 274 


Although these emission factors were intended for calculating criteria pollutant 
(VOC, N0 2 , CO) emissions for SIP emissions inventories, OMS derived emission factors for 
several HAPs, including benzene, so that national air toxics emissions could be estimated. To 
estimate benzene emissions, OMS expressed benzene emissions as a weight percent of exhaust 


8-5 




TABLE 8-2. OFF-ROAD EQUIPMENT TYPES AND HYDROCARBON EMISSION 

FACTORS INCLUDED IN THE NEVES (g/hp-hr) 

(FACTOR QUALITY RATING E) 


Equipment Type, Area and Mobile 
Source Code 

(2-stroke gas/4-stroke gas/diesel) 

2-Stroke Gasoline 
Engines 

4-Stroke Gasoline 
Engines 

Diesel Engines 

Exhaust 

Crank 

Case 

Exhaust 

Crank 

Case 

Exhaust 

Crank 

Case 

Lawn and Garden, 22-60/65/70-004- 

025 Trimmers/Edgers/Brush Cutters 

471.58* 

— 

50.78* 

7.98* 

— 

— 

010 Lawn Mowers 

436.80* 

— 

79.17* 

12.44* 

— 

— 

030 Leaf Blowers/Vacuums 

452.11* 

— 

40.74* 

6.40* 

~ 

— 

040 Rear-Engine Riding Mowers 

— 

— 

19.53* 

3.07* 

1.20 

0.02 

045 Front Mowers 

— 

— 

19.53* 

3.07* 

— 

— 

020 Chain Saws <4 hp 

625.80* 

— 

— 

— 

— 

— 

050 Shredders < 5 hp 

436.80* 

— 

79.17* 

12.44* 

~ 

— 

015 Tillers <5 hp 

436.80* 

— 

79.17* 

12.44* 

— 

— 

055 Lawn and Garden Tractors 

— 

— 

19.74* 

3.10* 

1.20. 

0.02 

UGvj UVJU SpliwlLri2> 

-- 

— 

*7Q 17* 

13 <u a 

1.20 

0 03 

035 Snow Blowers 

436.80* 

— 

79.17* 

12.44* 

— 

— 

065 Chippers/ Stump Grinders 

— 

— 

56.55 b 

12.44 b 

1.20 

0.02 

070 Commercial Turf Equipment 

436.80* 

— 

19.74* 

3.10* 

— 

— 

075 Other Lawn and Garden 

436.80* 

— 

79.17* 

12.44* 

1.20 

0.02 

Equipment 

Airport Service. 22-60/65/70-008- 

005 Aircraft Support Equipment 

~ 

— 

10.02 b 

2.20 b 

1.57 c 

0.03 c 

010 Terminal Tractors 

4.50 bd 

0.99 bd 

10.02 b 

2.20 b 

1.57 c 

0.03 c 

Recreational, 22-60/65/70-001- 

030 All-Terrain Vehicles (ATVs) 

1260.00*' 

— 

210.00*' 

33.00*' 

— 

— 

040 Minibikes 

— 

— 

210.00*' 

33.00*' 

— 

— 

010 Off-Road Motorcycles 

1260.00*' 

— 

150.00 b,e 

33.00 be 

— 

— 

050 Golf Carts 

1260.00*' 

— 

210.00*' 

33.00*' 

— 

— 

020 Snowmobiles 

228.90* 

— 

— 

— 

— 

— 

060 Specialty Vehicles Carts 

1260.00*' 

— 

210.00*' 

33.00*' 

1.20* 

0.02' 


8-6 


(continued) 








TABLE 8-2. CONTINUED 


Equipment Type, Area and Mobile 
Source Code 

(2-stroke gas/4-stroke gas/diesel) 

2-Stroke Gasoline 
Engines 

4-Stroke Gasoline 
Engines 

Diesel Engines 

Exhaust 

Crank 

Case 

Exhaust 

Crank 

Case 

Exhaust 

Crank 

Case 

Recreational Marine Vessels, 

22-82-005/010/020- 

.. 005 Vessels w/Inboard Engines 

873.67**' 

— 

108.69**' 

— 

24.39 f 

— 

010 Vessels w/Outboard Engines 

873.67**-' 

— 

131.57**-' 

28.94**' 

24.39 f 

0.49' 

015 Vessels w/Stemdrive Engmes 

873.67 b,f 

— 

108.69 bf 

— 

24.39 : 

-- 

020 Sailboat Auxiliary Inboard 

— 

— 

108.69**' 

— 

122.45' 

— 

Engines 

025 Sailboat Auxiliary Outboard 

873.67 bf 

— 

131.57 bf 

28.94 bf 

122.45' 

2.45' 

Engines 

Light Commercial, less than 50 HP, 

22-60/65/70-006- 

005 Generator Sets 

436.80* 

— 

19.95* 

3.14* 

1.20 

0.02 

010 Pumps 

8.99*° 

1.41*-° 

19.95* 

3.14* 

1.20 

0.02 

015 Air Compressors 

-- 

— 

19.95* 

3.14*. 

1.20 

0.02 

020 Gas Compressors 

6.42 bd 

1.4 l bd 

— 

— 

— 

— 

025 Welders 

— 

— 

19.95* 

3.14* 

1.20 

0.02 

.1 030 Pressure Washers 

— 

— 

19.95* 

3.14* 

1.20 

0.02 

Industrial, 22-60/65/70-003- 

010 Aerial Lifts 

4.50 bd 

1.49 bd 

10.02 b 

2.20 b 

1.57 c 

0.03 c 

102 Forklifts 

4.50 bd 

1.49 bd 

10.02 b 

2.20 b 

\.5T 

0.03 c 

030 Sweepers/Scrubbers 

4.50 bd 

1.49 bd 

10.02 b 

2.20 b 

1.57 c 

0.03 c 

040 Other General Industrial 

312.00 5 

— 

10.02 b 

2.20 b 

1.57 c 

0.03 c 

Equipment 

050 Other Material Handling 
Equipment 



10.02 b 

2.20 b 

1.5T 

0.03 c 

Construction, 22-60/65/70-002- 

003 Asphalt Pavers 

-- 

-- 

9.74 b 

2.14 b 

0.60 

0.01 

006 Tampers/Rammers 

436.80* 

— 

13.63* 

2.14* 

0.00 

0.00 

009 Plate Compactors 

436.80* 

— 

13.63* 

2.14* 

0.80 

0.02 

012 Concrete Pavers 

— 

— 

— 

— 

1.10 

0.02 


8-7 


(continued) 












TABLE 8-2. CONTINUED 


Equipment Type, Area and Mobile 
Source Code 

(2-stroke gas/4-stroke gas/diesel) 

2-Stroke Gasoline 
Engines 

4-Stroke Gasoline 
Engines 

Diesel Engines 

Exhaust 

Crank 

Case 

Exhaust 

Crank 

Case 

Exhaust 

Crank 

Case 

Construction, 22-60/65/70-002- (con't) 

015 Rollers 

— 

— 

19.43* 

3.05* 

0.80 

0.02 

018 Scrapers 

— 

— 

— 


0.70 c 

0.01 c 

021 Paving Equipment 

436.80* 

— 

13.63* 

2.14* 

1.01 

0.02 

024 Surfacing Equipment 

— 

— 

13.63* 

2.14* 

0.00 

0.00 

027 Signal Boards 

— 

— 

13.63* 

2.14* 

1.20 

0.02 

030 Trenchers 

— 

— 

9.74 b 

2.14 b 

1.54 c 

0.03 c 

033 Bore/Drill Rigs 

436.80* 

— 

9.74 b 

2.14 b 

1.41 c 

0.03° 

036 Excavators 

— 

— 

9.74 b 

2.14 b 

0.70" 

o 

b 

n 

039 Concrete/Industrial Saws 

— 

— 

13.63* 

2.14* 

1.41 e 

0.03 c 

042 Cement and Mortar Mixers 

— 

— 

13.63* 

2.14* 

1.01 

0.02 

045 Cranes 

— 

— 

9.74 b 

2.14 b 

1.26 c 

0.03 c 

048 Graders 

— 

— 

— 

— 

1.54 c 

0.03 c 

051 Off-Highway Trucks 

— 

— 

— 

— 

0.84 c 

0.02 c 

054 Crushing/Proc. Equipment 

— 

— 

9.74 b 

2.14 b 

1.4 l c 

0.03 c 

057 Rough Terrain Forklifts 

-- 

— 

9.74 b 

2.14 b 

1.68 c 

0.03 c 

060 Rubber Tire Loaders 

— 

— 

8.34 b 

1.83 b 

0.84 c 

0.02 c 

063 Rubber Tire Dozers 

— 

— 

— 

— 

0.84 c 

0.02 c 

066 Tractors/Loaders/Backhoes 

— 

— 

9.74 b 

2.14 b 

1.40 c 

0.03 c 

069 Crawler Tractors 

— 

. — 

— 

— 

1.26 c 

0.03 c 

072 Skid Steer Loaders 

— 

— 

9.74 b 

2.14 b 

2.10" 

0.04 c 

075 Off-Highway Tractors 

— 

— 

— 

— 

2.46 c 

0.05 c 

078 Dumpers/Tenders 

— 

— 

13.63* 

2.14* 

0.84 c 

0.02 c 

081 Other Construction Equipment 

— 

— 

9.74 b 

2.14 b 

1.41 c 

0.03 c 

Agricultural, 22-60/65/70-005- 

010 2-Wheel Tractors 

— 

— 

11.53* 

1.81* 

— 

— 

015 Agricultural Tractors 

— 

— 

8.24 b 

1.81 b 

2.23 c 

0.04 c 

030 Agricultural Mowers 

— 

— 

15.06* 

2.37* 

— 

— 

020 Combines 

— 

— 

10.77 b 

2.37 b 

1.26 c 

0.03 c 

035 Sprayers 

— 

— 

10.77 b 

2.37 b 

2.23 

0.04 


8-8 


(continued) 









TABLE 8-2. CONTINUED 


Equipment Type, Area and Mobile 
Source Code 

(2-stroke gas/4-stroke gas/diesel) 

2-Stroke Gasoline 
Engines 

4-Stroke Gasoline 
Engines 

Diesel Engines 

Exhaust 

Crank 

Case 

Exhaust 

Crank 

Case 

Exhaust 

Crank 

Case 

Agricultural, 22-60/65/70-005- (con't) 


• 





025 Balers 

— 

— 

— 

— 

2.23 

0.04 

040 Tillers > 5 hp 

— 

— 

79.17* 

12.44* 

1.20 

0.02 

045 Swathers 

— 

— 

10.77 b 

2.37 b 

0.90 

0.02 

050 Hydro Power Units 

-- 

-- 

15.08* 

2.37* 

2.23 

0.04 

055 Other Agricultural Equipment 

— 

— 

10.77 b 

2.37 b 

1.82 

0.04 

Logging, 22-60/65/70-007- 







005 Chain Saws > 4 hp 

319.20* 

— 

— 

— 

— 

— 

010 Shredders >5 hp 

— 

— 

19.53* 

3.07* 

— 

— 

015 Skidders 

— 

— 

-- 

— 

0.84 c 

0.02 c 

non 'D...- 

-- 

-- 

-- 

-- 

0 £d c 

0 02 e 


* Adjusted for in-use effects using small utility engine data. 
b Adjusted for m-use effects using heavy-duty engine data. 
e Exhaust HC adjusted for transient speed and/or transient load operation. 
d Emission factors for 4-stroke propane-fueled equipment. 
e g/hr. 

' g/gallon. 

" = Not applicable. 


8-9 









hydrocarbons plus crank case hydrocarbons. In OMS's analysis, it was assumed that the 
weight percent of benzene for all off-road sources was 3 percent of exhaust hydrocarbons. 275 
A range of OMS-recommended weight percent benzene factors for general categories of 
off-road equipment are presented in Table 8-3. 274 Note that development of equipment-specific 
emission factors is underway, and when available, those emission factors should be considered 
instead. To obtain benzene emission estimates from equipment in these general categories of 
off-road equipment, the benzene weight percent factors noted in Table 8-3 can be applied to 
hydrocarbon estimates from the different NEVES equipment types. 

The NEVES equipment emission factors can be used directly to estimate 
emissions from specific equipment types if local activity data is available. If general nonroad 
emission estimates are required, States may choose one of the 33 nonattainment areas, studied 
in the NEVES report, that is similar in terms of climate and economic activity; the NEVES 
nonattainment area can be adjusted to estimate emissions in another state by applying a 
population ratio of the two areas to the NEVES estimate. The NEVES report also has 
estimates for individual counties of the 33 nonattainment areas such that States or local 
governments may also produce regional or county inventories by adjusting the NEVES county 
estimates relative to the population of the different counties. Counties can be chosen from 
several of the 33 NEVES nonattainment areas if appropriate. For further details on how to 
calculate emissions from specific equipment types refer to NEVES, for details on calculating 
emissions of nonroad sources in general see Reference 271. 

8.3 MARINE VESSELS 

For commercial marine vessels, the NEVES report includes VOC emissions for 
six nonattainment areas taken from a 1991 EPA study Commercial Marine Vessel Contribution 
to Emission Inventories} 16 This study provided hydrocarbon emission factors for ocean-going 
commercial vessels and harbor and fishing vessels. The emission factors are shown in 
Table 8-4. 


8-10 


TABLE 8-3. WEIGHT PERCENT FACTORS FOR BENZENE 


As Tested Use 

Recommended Off-Road Category 

Benzene % by 
Weight of FID HC a 

Diesel Forklift Engine 

Large Utility Equipment 

2.4-3.0 

Direct Injection Diesel 
Automobile 

Large Utility Equipment (Cyclic) 
Construction Equipment 

3.1-6.5 

Indirect Injection Diesel 
Automobile 

Large Utility Equipment (Cyclic) 
Marine, Agricultural Large Utility 
Construction Equipment 

- 1.5-2.1 

Leaded Gasoline Automobiles 

Large Utility Equipment (Cyclic) 
Marine, Agricultural, Large Utility 

3.0-3.4 

Leaded Gasoline Automobiles 

(12% Misfire) 

Large Utility Equipment (Cyclic) 

Marine, Agricultural, Large Utility 

1.1-1.3 

1973 Highway Traffic 


3.0 


Source: Reference 274. 


lu i u.i uctiimeasured P~lame io niz aiion Detection. 


Ocean-going marine vessels fall into one of two categories-those with steam 
propulsion and those with motor propulsion. Furthermore, they emit pollution under two 
modes of operation: underway and at dockside (hotelling). Most steamships use boilers rather 
than auxiliary diesel engines while hotelling. Currently, there are no benzene toxic emission 
fractions for steamship boiler burner emissions. The emission factors for motor propulsion 
systems are based on emission fractions for heavy-duty diesel vehicle engines. For auxiliary 
diesel generators, emission factors are available only for 500 KW engines, since the 1991 
Booz-Allen and Hamilton report indicated that almost all generators were rated at 500 KW or 
more. 


For harbor and fishing vessels, benzene emission factors for diesel engines are 
provided for the following horsepower categories - less than 500 hp, 500 to 1,000 hp, 

1,000 to 1,500 hp, 1,500 to 2,000 hp, and greater than 2,000 hp. In each of these categories, 
emission factors are developed for full, cruise, and slow operating modes. Toxic emission 


8-11 






TABLE 8-4. BENZENE EMISSION FACTORS FOR COMMERCIAL MARINE 

VESSELS 


Operating Plant 
(operating mode/rated output) 

Benzene Emission Factor 
(lb/1000 gal fuel) 2 

Ocean-Going Commercial 

• 

Motor Propulsion 

All underway modes 

0.25 

Auxiliary Diesel Generators 

^ -• - - --- 

500 KW (50% load) 

0.87 

Harbor and Fishing 

. 

Diesel Engines 

< 500 hp 

Full 

0.22 

Cruise 

0.54 

Slow 

0.60 

500-1000 hp 

Full 

0.25 

Cruise 

0.18 

Slow 

0.18 

1000-1500 hp 


Full 

0.25 

Cruise 

0.25 

Slow 

0.25 

1500-2000 hp 

Full 

0.18 

Cruise 

0.25 

Slow 

0.25 

2000+ hp 

- 

Full 

0.23 

Cruise 

0.18 

Slow 

0.24 

Gasoline Engines - all hp 

ratings 


Exhaust (g/bhp-hr) 

0.35 

Evaporative (g/hr) 

0.64 


1 Benzene exhaust emission factors were estimated by multiplying HC emission factors by benzene TOG 
fractions. Benzene exhaust emission fractions of HC for all marine diesel engines were assumed to be the same 
as the TOG emission fraction for heavy-duty diesel vehicles -- 0.0106. The benzene exhaust emission fraction 
for marine gasoline engines was assumed to be the same as the exhaust TOG emission fraction for heavy duty 
gasoline vehicles - 0.0527. The benzene evaporative emission fraction was also assumed to be the same as the 
evaporative emission HC fraction for heavy duty gasoline vehicles -- 0.0104. 


8-12 






factors are also provided for gasoline engines in this category. These emission factors are not 
broken down by horsepower rating, and are expressed in grams per. brake horsepower hour 
rather than pounds per thousand gallons of fuel consumed. 

8.4 LOCOMOTIVES 

As noted in the U.S. EPA's Procedures for Emission Inventory Preparation , 
Volume IV: Mobile Sources, 271 locomotive activity can be defined as either line haul or yard 
activities. Line haul locomotives, which perform line haul operation, generally travel between 
distant locations, such as from one city to another. Yard locomotives, which perform yard 
operations, are primarily responsible for moving railcars within a particular railway yard. 

The OMS has included locomotive emissions in its Motor Vehicle-Related Air 
Toxic Study. 20 The emission factors used for locomotives in this report are derived from the 
heavy-duty diesel on-road vehicles as there are no emission factors specifically for 
locomotives. To derive toxic emission factors for heavy diesel on-road vehicles, hydrocarbon 
emission factors were speciated. The emission factors provided in this study (shown in 
Table 8-5) are based on g/mile traveled. 20 


TABLE 8-5. BENZENE EMISSION FACTORS FOR LOCOMOTIVES 


Source 

Toxic Emission Fraction 

Emission Factor (lb/gal) 

Line Haul Locomotive 

0.0106 a 

0.00022 

Yard Locomotive 

0.0106 a 

0.00054 


Source: Reference 20. 

1 These fractions are found in Appendix B6 of EPA, 1993, and represent toxic emission fractions for heavy-duty 
diesel vehicles. Toxic fractions for locomotives are assumed to be the same, since no fractions specific for 
locomotives are available. It should be noted that these fractions are based on g/mile emissions data, whereas 
emission factors for locomotives are estimated in lb/gal. The toxic emission fractions were multiplied by the 
HC emission factors to obtain the toxic emission factors. 






8.5 


AIRCRAFT 


There are two main types of aircraft engines in use: turbojet and piston. A 
kerosene-like jet fuel is used in the jet engines, whereas aviation gasoline with a lower vapor 
pressure than automotive gasoline is used for piston engines. The aircraft fleet in the United 
States numbers about 198,000, including civilian and military aircraft. 277 Most of the fleet is 
of the single- and twin-engine piston type and is used for general aviation. However, most of 
the fuel is consumed by commercial jets and military aircraft; thus, these types of aircraft 
contribute more to combustion emissions than does general aviation. Most commercial jets 
have two, three, or four engines. Military aircraft range from single or dual jet engines, as in 
fighters, to multi-engine transport aircraft with turbojet or turboprop engines. 278 


Despite the great diversity of aircraft types and engines, there are considerable 
data available to aid in calculating aircraft- and engine-specific hydrocarbon emissions, such as 

the database maintained by the Federal Aviation Administration (FAA) Office of Environment 

and Energy, FAA Aircraft Engine Emissions Database (FAEED). These hydrocarbon 
emission factors may be used with weight percent factors of benzene in hydrocarbon emissions 
to estimate benzene emissions from this source. Benzene weight percent factors in aircraft 

hydrocarbon emissions are reported in an EPA memorandum 280 concerning toxic emission 
fractions for aircraft, and are presented in Table 8-6. 


TABLE 8-6. BENZENE CONTENT IN AIRCRAFT LANDING AND TAKEOFF 


EMISSIONS 


Description 

AMS Code 

Weight Percent 
Benzene 

Factor Quality 

Military Aircraft 

22-75-001-000 

2.02 

B 

Commercial Aircraft 

22-75-020-000 

1.94 

B 

Air Taxi Aircraft 

22-75-060-000 

3.44 

C 

General Aviation 

22-75-050-000 

3.91 

C 


Source: Reference 279 and 280. 


8-14 






Current guidance from EPA for estimating hydrocarbon emissions from aircraft 
appears in Procedures for Emission Inventory Preparation; Volume IV: Mobile Sources. 271 
The landing/takeoff (LTO) cycle is the basis for calculating aircraft emissions. The operating 
modes in an LTO cycle are (1) approach, (2) taxi/idle in, (3) taxi/idle out, (4) takeoff, and 
(5) climbout. Emission rates by engine type and operating mode are given in the FAEED. To 
use this procedure, the aircraft fleet must be characterized and the duration of each operating 
mode determined. From this information, hydrocarbon emissions can be calculated for one 
LTO for each aircraft type in the fleet. To determine total hydrocarbon emissions from th? 
fleet, the emissions from a single LTO for the aircraft type would be multiplied by the number 
of LTOs for each aircraft type. 

The emission estimation method noted above is the preferred approach as it 
takes into consideration differences between new and old aircraft. If detailed aircraft 
information is unavailable, hydrocarbon emission indices for representative fleet mixes are 
provided in the emissions inventory guidance document Procedures for Emissions Inventory 
Preparation ; Volume IV: Mobile Sources. 271 The hydrocarbon emission indices are 
0.394 pounds per LTO (0.179 kg per LTO) for general aviation and 1.234 pounds per LTO 
(0.560 kg per LTO) for air taxis. 

The benzene fraction of the hydrocarbon total (in terms of total organic gas) can 
be estimated by using the percent weight factors from Table 8-6. Because air taxis have larger 
engines and more of the fleet is equipped with turboprop and turbojet engines than is the 
general aviation fleet, the percent weight factor is somewhat different from the general aviation 
emission factor. 

8.6 ROCKET ENGINES 

Benzene has also been detected from rocket engines tested or used for space 
travel. Two types of rocket engines are currently in use: sustainer rocket engines, which 
provide the main continual propulsion, and booster rocket engines, which provide additional 


8-15 


force at critical stages of the lift off, such as during the separation of sections of the rocket 
fuselage. 


Source testing of booster rocket engines using RP-1 (kerosene) and liquid 
oxygen have been completed at an engine test site. Tests for benzene were taken for eight test 
runs sampling at four locations within the plume envelope below the test stand. Results from 
these tests yielded a range of benzene emission factors—0.31 to 0.561 lb/ton (0.155 to 
0.28° kg'Ms) of fu? 1 combusted—providing an average emission factor of 0.431 lb/ton 
(0.215 kg/Mg) of fuel combusted, as presented in Table 8-7. 282 It should be noted that booster 
fuel consumption is approximately five times that of sustainer rocket engines. 


TABLE 8-7. EMISSION FACTORS FOR ROCKET ENGINES 


AMS Code Emissions Source 

Emission Factor 
lb/ton (kg/Mg) 

Factor Rating 

28-10-040-000 Booster rocket engines using 

0.431 (0.215) 3 

C 

RP-1 (kerosene) and liquid 



oxygen as fuel 




Source: Reference 282. 


a Emission factors are in lb (kg) of benzene emitted per ton (Mg) of fuel combusted. 


8-16 





SECTION 9.0 

SOURCE TEST PROCEDURES 


Benzene emissions from ambient air, mobile sources, and stationary sources can 
be measured utilizing the following test methods: 283 

• EPA Method 0030: Volatile Organic Sampling Train (VOST) with EPA 

Method 5040/5041: Analysis of Sorbent Cartridges from VOST; 

• EPA Method 18: Measurement of Gaseous Organic Compound 
Emissions bv Gas ChromatograDhv: 

• EPA method TO-1: Determination of Volatile Organic Compounds in 
Ambient Air Using Tenax® Adsorption and Gas Chromatography/Mass 
Spectrometry (GC/MS); 

• EPA method TO-2: Determination of Volatile Organic Compounds in 
Ambient Air by Carbon Molecular Sieve Adsorption and Gas 
Chromatography/Mass Spectrometry; 

• EPA Method TO-14: Determination of Volatile Organic Compounds 
(VOCs) in Ambient Air Using SUMMA® Passivated Canister Sampling 
and Gas Chromatographic (GC) Analysis; 

• EPA Exhaust Gas Sampling System, Federal Test Procedure (FTP); and 

• Auto/Oil Air Quality Improvement Research (AQERP) Speciation 
Methodology. 

If applied to stack sampling, the ambient air monitoring methods may require 
adaptation or modification. To ensure that results will be quantitative, appropriate precautions 
must be taken to prevent exceeding the capacity of the methodology. Ambient methods that 


9-1 




require the use of sorbents are susceptible to sorbent saturation if high concentration levels 
exist. If this happens, breakthrough will occur and quantitative analysis will not be possible. 

9.1 EPA METHOD 0030 284 

The VOST from SW-846 (third edition) is designed to collect VOCs from the 
stack gas effluents of hazardous waste incinerators, but it may be used for a variety of 

stationary sources. The VOST method was designed to collect volatile organics with boiling 
points in the range of 30°C to 100°C. Many compounds with boiling points above 100°C may 
also be effectively collected using this method. Because benzene's boiling point is about 

80.1 °C, benzene concentrations can be measured using this method. Method 0030 is 
applicable to benzene concentrations of 10 to 100 or 200 parts per billion by volume (ppbv). If 
the sample is somewhat above 100 ppbv, saturation of the instrument will occur. In those 
cases, another method, such as Method 18, should be used. Method 0030 is often used in 
conjunction with analytical Method 5040/5041. 

Figure 9-1 presents a schematic of the principal components of the VOST. 241 In 
most cases, 20 L of effluent stack gas are sampled at an approximate flow rate of 1 L/min, 
using a glass-lined heated probe. The gas stream is cooled to 20°C by passage through a 
water-cooled condenser and the volatile organics are collected on a pair of sorbent resin traps. 
Liquid condensate is collected in the impinger located between the two resin traps. The first 
resin trap (front trap) contains about 1.6 g Tenax® and the second trap (back trap) contains 
about 1 g each of Tenax® and petroleum-based charcoal (SKC lot 104 or equivalent), 3:1 by 
volume. 

The Tenax® cartridges are then thermally desorbed and analyzed by 
purge-and-trap GC/MS along with the condensate catch as specified in EPA 
Methods 5040/5041. Analysis should be conducted within 14 days of sample collection. 


9-2 


Isolation Valvas 



9-3 


Figure 9-1. Volatile Organic Sampling Train (VOST) 































































The sensitivity of Method 0030 depends on the level of interferences in the 
sample and the presence of detectable levels of benzene in the blanks. Interferences arise 
primarily from background contamination of sorbent traps prior to or after use in sample 
collection. Many interferences are due to exposure to significant concentrations of benzene in 
the ambient air at the stationary source site and exposure of the sorbent materials to solvent 
vapors prior to assembly. 

To alleviate these problems, the level of the lab blank should be determined in 
advance. Calculations should be made based on feed concentration to determine if blank level 
will be a significant problem. Benzene should not be chosen as a target compound at very low 
feed levels because it is likely there will be significant blank problems. 283 

One of the disadvantages of the VOST method is that because the entire sample 
is analyzed, duplicate analyses cannot be performed. On the other hand, when the entire 
sample is analyzed, the sensitivity is increased. Anotner advantage is that oreakthrough 
volume is not greatly affected by humidity. 

9.2 EPA METHODS 5040/504l 283 - 284 

The contents of the sorbent cartridges (collected using EPA Method 0030) are 
spiked with an internal standard and thermally desorbed for 10 minutes at 80 °C with 
organic-free nitrogen or helium gas (at a flow rate of 40 mL/min), bubbled through 5 mL of 
organic-free water, and trapped on an analytical adsorbent trap. After the 10-minute 
desorption, the analytical adsorbent trap is rapidly heated to 180°C, with the carrier gas flow 
reversed so that the effluent flow from the analytical trap is directed into the GC/MS. The 
volatile organics are separated by temperature-programmed gas chromatography and detected 
by low-resolution mass spectrometry. The concentrations of the volatile compounds are 
calculated using the internal standard technique. EPA Methods 5030 and 8420 may be 
referenced for specific requirements for the thermal desorption unit, purge-and-trap unit, and 
GC/MS system. 


9-4 


A diagram of the analytical system is presented in Figure 9-2. The Tenax® 
cartridges should be analyzed within 14 days of collection. The detection limits for 
low-resolution MS using this method are usually about 10 to 20 ng or 1 ng/L (3 ppbv). 

The primary difference between EPA Methods 5040 and 5041 is the fact that 
Method 5041 utilizes the wide-bore capillary column (such as 30 m DB-624), whereas 
Method 5040 calls for a stainless steel or glass-packed column (1.8 x 0.25 cm I.D., 1 percent 

SP'1000 on ^ 0/90 rnesb Carbopack BV 

9.3 EPA METHOD 18 285 

EPA Method 18 is the preferred method for measuring higher levels of benzene 
from a source (approximately 1 pan per million by volume [ppmv] to the saturation point of 
benzene in air). In Method 18, a sample of the exhaust gas to be analyzed is drawn into a 
stainless steel or glass sampling bulb or a Tedlar® or aluminized Mylar® bag as shown in 
Figure 9-3. 285 The Tedlar® bag has been used for some time in the sampling and analysis of 
source emissions for pollutants. The cost of the Tedlar® bag is relatively low, and analysis by 
gas chromatography is easier than with a stainless steel cylinder sampler because pressurization 
is not required to extract the air sample in the gas chromatographic analysis process. 286 The 
bag is placed inside a rigid, leak-proof container and evacuated. The bag is then connected by 
a Teflon® sampling line to a sampling probe (stainless steel, Pyrex® glass, or Teflon®) at the 
center of the stack. The sample is drawn into the bag by pumping air out of the rigid 
container. 


The sample is then analyzed by gas chromatography coupled with flame 
ionization detection. Based on field and laboratory validation studies, the recommended time 
limit for analysis is within 30 days of sample collection. 287 One recommended column is the 
8-ft x 1/8 in. O.D. stainless steel column packed with 1 percent SP-1000 in 
60/80 carbopack B. However, the GC operator should select the column and GC conditions 


9-5 




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9-6 




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9-7 


Figure 9-3. Integrated Hag Sampling Train 































that provide good resolution and minimum analysis time for benzene. Zero helium or nitrogen 
should be used as the carrier gas at a flow rate that optimizes the resolution. 

The peak areas corresponding to the retention times of benzene are measured 
and compared to peak areas for a set of standard gas mixtures to determine the benzene 
concentrations. The detection limit of this method ranges from about 1 ppm to an upper limit 
governed by the FID saturation or column overloading. However, the upper limit can be 
extended by diluting the stack gases with an inert gas or by using smaller gas sampling loops. 


The EPA's Atmospheric Research and Exposure Assessment Laboratory has 
produced a modified version of Method 18 for stationary source sampling. 286,288 One 
difference from the original method is in the sampling rate, which is reduced to allow 
collection of more manageable gas volumes. By reducing the gas volumes, smaller Tedlar® 
bags can be used instead of the traditional 25-L or larger bags, which are not very practical in 
the field, especially when a large number of samples is required. 286 A second difference is the 
introduction of a filtering medium to remove entrained liquids, which improves benzene 
quantitation precision. 


The advantage of EPA Method 18 is that it is rapid and relatively inexpensive. 
However, it does require a fully equipped chromatography lab and a skilled analyst. 

9.4 EPA METHOD TO-1 (COMPENDIUM) 


Ambient air concentrations of benzene can be measured using EPA 
Method TO-1 from Compendium of Methods for the Determination of Toxic Organic 
Compounds in Ambient Air , 289 This method is used to collect and determine nonpolar, volatile 
organics (aromatic hydrocarbons, chlorinated hydrocarbons) that can be captured on Tenax® 
and determined by thermal desorption techniques. The compounds determined by this method 
have boiling points in the range of 80 to 200 °C. 


9-8 


Method TO-1 can measure benzene concentrations from about 3 to 150 ppbv. 
The advantages and disadvantages are about the same as for the VOST method, and costs are 
comparable. 


Figure 9-4 presents a block diagram of the TO-1 system. Figure 9-5 presents a 
diagram of a typical Tenax® cartridge. 289 Ambient air is drawn through the cartridge, which 
contains approximately 1 to 2 grams of Tenax®. The benzene is trapped on the Tenax® 
cartridge, which is then capped and sent to the laboratory for analysis utilizing GC/MS 
according to the procedures specified in EPA Method 5040. 

The exact run time, flow rate, and volume sampled varies from source to source 
depending on .the expected concentrations and the required detection limit. Typically, 10 to 
20 L of ambient air are sampled. Estimated breakthrough volume of Tenax® (for benzene) is 
19 L/g at 38°C. Analysis should be conducted within 14 days of collection. A capillary 
column (tused silica SE-30 or OV-lj navmg an internal diameter ot 0.3 mm and a length oi 
50 m is recommended. The MS identifies and quantifies the compounds by mass 
fragmentation or ion characteristic patterns. Compound identification is normally 
accomplished using a library search routine on the basis of GC retention time and mass 
spectral characteristics. 

9.5 EPA METHOD TO-2 283 289 

Method TO-2 is used to collect and determine highly volatile, non-polar 
organics (vinyl chloride, vinylidene chloride, benzene, toluene) that can be captured on a 
carbon molecular sieve (CMS) trap and determined by thermal desorption techniques. The 
compounds to be determined by this technique have boiling points in the range of 15 to 120°C. 
Method TO-2 has the same advantages and disadvantages as the VOST method. 

Figure 9-6 presents a diagram of a CMS trap construction and Figure 9-7 shows 
the GC/MS system used in analyzing the CMS cartridges. 289 Air is drawn through a cartridge 


9-9 


Purge Gas 



9-10 






























(a) Glass Cartridge 


— 1/2* to 
1 / 8 * 

Reducing 



(b) Metal Cartridge 

Figure 9-5. Typical Tenax® Cartridge 


Source: Reference 289. 


9-11 


ERG BZ 95.ds4 





























Thermocouple 



End 

Cap 


Thermocouple 

Connector 


Heater 

Connector 


Figure 9-6. Carbon Molecular Sieve Trap (CMS) Construction 
Source: Reference 289. 


9-12 





















Column 


Figure 9-7. GC/MS Analysis System for CMS Cartridges 
Source: Reference 289. 


9-13 


































con tainin g 0.4 g of a CMS adsorbent. The cartridge is analyzed in the laboratory by flushing 
with dry air to remove adsorbed moisture and purging the sample with helium while heating 
the cartridge to 350 to 400 ~'C. The desorbed organics are collected in a cryogenic trap and 
flash-evaporated into a GC followed by an MS. Only capillar.- GC techniques should be used. 
The GC temperature is increased through a temperature program and the compounds are eluted 
from the column on the basis of boiling points. The MS identifies and quantifies the 
compounds by mass fragmentation patterns. Compound identification is normally 
accomplished using a library search routine on the basis of GC retention time and mass 
spectral characteristics. The most common interferences are structural isomers. 

9.6 EPA METHOD TO-14 283 - 289 

Ambient air concentrations of benzene can also be measured ’using EPA 
Method TO-14 from Compendium of Methods for the Determination of Toxic Organic 
Compounds in Amoiem Air.- Inis method is oasea on collection of a whoie-air sampie in 
SUMMA* passivated stainless steel canisters and is used to determine semivolatile and volatile 
organic compounds. 

This method is applicable to specific semivolatiles and VOCs that have been 
tested and determined to be stable when stored in pressurized and subatmospheric pressure 
canisters. Benzene has been successfully measured in the parts-per-billion- by-volume level 

using this method. 

Figure 9-8 presents a diagram of the canister sampling system. 289 Air is drawn 
through a sampling train into a pre-evacuated sample SUMMA* canister. The canister is 
attached to the analytical system. Water vapor is reduced in the gas stream by a Nation dryer 
and VOCs are concentrated by collection into a cryogenicallv cooled trap. The cryogen is 
removed and the temperature of the sample raised to volatilize the sample into a 
high-resolution GC column. The GC temperature is increased through a temperature program 
and the compounds are eluted from the column on the basis of boiling points into a detector. 

9-14 









To AC 



Figure 9-8. Sampler Configuration for EPA Method TO-14 
Source: Reference 289. 


9-15 















































































































































The choice of detector depends on the specificity and sensitivity required by the 
analysis. Non-specific detectors suggested for benzene analysis include flame ionization 
detectors (FID) with detection limits of about 4 ppbv and photoionization detectors (PID), 
which are about 25 times more sensitive than FID. Specific- detectors include an MS operating 
in the selected ion mode or the SCAN mode, or an ion trap detector. Identification errors can 
be reduced by employing simultaneous detection by different detectors. The recommended 
column for Method TO-14 is an HP OV-1 capillary type with 0.32 mm I.D. and a 0.88 /xm 
cross-linked methyl silicone coating or equivalent. Samples should be analyzed within 14 days 
of collection. One of the advantages of Method TO-14 is that multiple analyses can be 
performed on one sample. 

9.7 . FEDERAL TEST PROCEDURE (FTP) 

The most widely used test procedure for sampling emissions from vehicle 
exhaust is the FTP, which was developed in 1974. 290 ' 25- The FTP uses the Urban 
Dynamometer Driving Schedule (UDDS), which is 1,372 seconds in duration. An automobile 
is placed on a chassis dynamometer, where it is run according to the following schedule: 

505 seconds of a cold start; 867 seconds of hot transient; and 505 seconds of a hot start. (The 
definitions of the above terms can be found in the FTP description in the 40 CFR, Part 86). 290 
The vehicle exhaust is collected in Tedlar® bags during the three testing stages. 

The most widely used method for transporting vehicle exhaust from the vehicle 
to the bags is a dilution tube sampling arrangement identical to the system used for measuring 
criteria pollutants from mobile sources. 290,293 Dilution techniques are used for sampling auto 
exhaust because, in theory, dilution helps simulate the conditions under which exhaust gases 
condense and react in the atmosphere. Figure 9-9 shows a diagram of a vehicle exhaust 
sampling system. 290 294 Vehicle exhausts are introduced at an orifice where the gases are 
collected and mixed with a supply of filtered dilution air. The diluted exhaust stream flows at 
a measured velocity through the dilution tube and is sampled isokinetically. 


9-16 




Dilution Air Exhaust Sample 

Sample Bag 


dia-«f-M1d-S>00fr6 



9-17 


Source: Reference 290. 
























































The major advantage to using a dilution tube approach is that exhaust gases are 
allowed to react and condense onto particle surfaces prior to sample collection, providing a 
truer composition of exhaust emissions as they occur in the atmosphere. Another advantage is 
that the dilution tube configuration allows simultaneous monitoring of hydrocarbons, CO, C0 2 , 
and NO x . Back-up sampling techniques, such as filtration/adsorption, are generally 
recommended for collection of both particulate- and gas-phase emissions. 292 

9.8 AUTO/OIL AIR QUALITY IMPROVEMENT RESEARCH PROGRAM 

SPECIATION METHOD 

Although there is no EPA-recommended analytical method for measuring 
benzene from vehicle exhaust, the AQIRP method for the speciation of hydrocarbons and 
oxygenates is widely used. 292,295 Initially, the AQIRP method included three separate analytical 
approaches for analyzing different hydrocarbons, but Method 3, the method designated for 
benzene, was dropped from use because of wandering retention times. Method 2 can be used 
to measure benzene from auto exhaust but some interferences, which will be discussed later, 
may occur. 


This analytical method calls for analyzing the bag samples collected by the FTP 
method by injecting them into a dual-column GC with an FID. A recommended pre-column is 
a 2 m x 0.32 mm I.D. deactivated fused silica (J&W Scientific Co.) connected to an analytical 
column that is 60 m DB-1, 0.32 mm I.D., 1 film thickness. 295 The detection limit for 
benzene with this method is 0.005 ppmC. 

The peak areas corresponding to the retention times of benzene are measured 
and compared to peak areas for a set of standard gas mixtures to determine the benzene 
concentrations. However, there is a problem with benzene co-eluting with 
1-methylcyclopentene. Therefore, the analyst should be aware of this potential interference. 


9-18 


The amount of benzene in a sample is obtained from the calibration curve in 
units of micrograms per sample. Collected samples are sufficiently stable to permit 6 days of 
ambient sample storage before analysis. If samples are refrigerated, they are stable for 
18 days. 


9-19 




























































' 



































































SECTION 10.0 
REFERENCES 


1. Toxic Chemical Release Reporting. Community Right-To-Know. 52 FR 21152. 

June 4, 1987. 

2. U.S. EPA. Procedures for Preparing Emission Factor Documents. Research Triangle 
Park, North Carolina: U.S. Environmental Protection Agency, Office of Air Quality 

Planning and Standards, 1997. 

3. Factor Information Retrieval System Version 2.62 (FIRE 2.62). Research Triangle 
Park, North Carolina: U.S. Environmental Protection Agency, March 1994. 

4. Sittig, M. Handbook of Toxic and Hazardous Chemicals and Carcinogens. Park 
Ridge, New Jersey: Noyes Data Company, 1989. 

5. R.J. Lewis, Sr. ed. Hazardous Chemicals Desk Reference, 2nd ed. New York, 

New York: Von Nostrand Reinhold, 1991. pp. 115 to 117. 

6. U.S. EPA. Atmospheric Reaction Products of Organic Compounds. 
EPA-560/12-79-001. Washington, D.C.: U.S. Environmental Protection Agency, 
1979. 

7. Handbook of Chemistry and Physics. Weast, R.C., ed. Boca Raton, Florida: CRC 
Press, Inc., 1980. 

8. Brewster, R.Q. and W.E. McEwen. Organic Chemistry , 3rd ed. Englewood Cliffs, 
New Jersey: Prentice Hall, Inc., 1963. 

9. U.S. EPA. Atmospheric Benzene Emissions. EPA-450/3-77-029. Research Triangle 
Park, North Carolina: U.S. Environmental Protection Agency, 1977. pp. 4-19 to 
4-25. 

10. Purcell, W.P. Benzene. In: Kirk Other Encyclopedia of Chemical Technology. 

Vol. 3. New York, New York: John Wiley and Sons, 1978. 


10-1 


11. SRI International. 1993 Directory of Chemical Producers. Menlo Park, California: 
SRI International, 1993. 

12. Benzene. Chemical Products Synopsis. Asbury Park, New Jersey: Mannsville 
Chemical Products Corporation, July 1993. 

13. U.S. EPA. The Environmental Catalog of Industrial Processes. Vol. I-Oil/Gas 
Production, Petroleum Refining, Carbon Black and Basic Petrochemicals. 
EPA-600/2-76-051a. Research Triangle Park, North Carolina: U.S. Environmental 
Protection Agency, 1976. 

0 

14. U.S. EPA. Ethylene. Report 3. In: Organic Chemical Manufacturing, Vol. 9/. 

Selected Processes. EPA-450/3-80-028d. Research Triangle Park, North Carolina: 
U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, 
1978. 

15. Dossett, A.P. Dealkylation of Toluene and Xylene. In: Toluene, the Xylenes and 
Their Industrial Derivatives, Hancock, E.G., ed. New York, New York: Elsevier 
Scientific Publishing Company, 1982. pp. 157-171. 

16. Acetone. Chemical Products Synopsis. Asbury Park, New Jersey: Mannsville 
Chemical Products Corporation, March 1995. 

17. Cyclohexane. Chemical Products Synopsis. Asbury Park, New Jersey: Mannsville 
Chemical Products Corporation, April 1993. 

18. Aniline. Chemical Products Synopsis. Asbury Park, New Jersey: Mannsville 
Chemical Products Corporation, December 1992. 

19. Dylewski, S.W. Chlorobenzenes: Report 3. In: Organic Chemical Manufacturing, 
Vol. 6: Selected Processes. EPA-450/3-80-028a. Research Triangle Park, North 
Carolina: U.S. Environmental Protection Agency, Office of Air Quality Planning and 
Standards, 1980. 

20. U.S. EPA. Motor Vehicle-Related Air Toxic Study. EPA-420/R-93-005. Ann Arbor, 
Michigan: U.S. Environmental Protection Agency, Office of Mobile Sources, 

April 1993. 

21. U.S. Department of Transportation. Highway Statistics 1992. Washington, D.C.: 
U.S. Department of Transportation, 1993. 

22. U.S. EPA. Compilation of Air Pollutant Emission Factors, 5th ed. (AP-42), Vol. I: 
Stationary Point and Area Sources, Supplement A, Section 6.18: “Benzene, Toluene, 

and Xylenes,” 1995. Not yet published. 


10-2 


23. U.S. EPA. Materials Balance for Benzene Level II. EPA-560/13-80-009. 

Washington, D.C.: U.S. Environmental Protection Agency, 1980. pp. 2-6 to 2-34. 

t f 

24. Toluene. Chemical Products Synopsis. Asbury Park, New Jersey: Mannsville 
Chemical Products Corporation, October 1992. 

25. U.S. EPA. Evaluation of Benzene—Related Petroleum Process Operations. 
EPA-450/3-79-022. Research Triangle Park, North Carolina: U.S. Environmental 
Protection Agency, Office of Air Quality Planning and Standards, 1978. 

26. Otani, S. Benzene, Xylene Bonanza from Less-Price Aromatics. Chemical 

Engineering ^7n6Vl 18-120 1970 

27. U.S. EPA. Locating and Estimating Sources of Toluene Emissions. 
EPA-454/R-93-047. Research Triangle Park, North Carolina: U.S. Environmental 
Protection Agency, Office of Air Quality Planning and Standards, 1993. 

28. Standifer, R.L. Ethylene: Report 3. in: Organic Chemical Manufacturing. Vol. 9: 
Selected Processes. EPA-450/3-80-028d. Research Triangle Park, North Carolina: 
U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, 
1981. 

29. Kniel, L., et al. Ethylene. In: Kirk-Othmer Encyclopedia of Chemical Technology. 
Vol. 9. New York, New York: John Wiley and Sons, 1980. pp. 393-431. 

30. Sittig, M. Aromatic Hydrocarbon Manufacture and Technology. Park Ridge, New 
Jersey: Noyes Data Company, 1976. 

31. U.S. EPA. Compilation of Air Pollutant Emission Factors , 5th ed. (AP-42), Vol. I: 
Stationary Point and Area Sources, Section 5.3: “Natural Gas Processing,” Research 
Triangle Park, North Carolina: U.S. Environmental Protection Agency, Office of Air 
Quality Planning and Standards, January 1995. 

32. Davis, B.C. “Implementation Options for MACT Standards for Emissions from 
Leaking Equipment.” Presented at the 84th Annual Meeting and Exhibition of the Air 
and Waste Management Association. Vancouver, British Columbia: June 16-21, 1991. 

33. AP-42, 5th ed., op. cit., reference 31. Section 7.1: “Organic Liquid Storage Tanks,” 
1995. 

34. U.S. EPA. Evaluation of the Efficiency of Industrial Flares: Flare Head Design and 
Gas Composition. EPA-600/2-85-106. Research Triangle Park, North Carolina: 

U.S. Environmental Protection Agency, 1985. 





10-3 



35. U.S. EPA. Background Memorandum for Section 5.35 of AP-42, Review of 
Information on Ethylene Production. Research Triangle Park, North Carolina: 

U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, 
September 1993. 

36. National Emission Standards for Hazardous Air Pollutants for Source Categories; Coke 
Oven Batteries. Proposed rule, 57 FR 57534, December 4, 1992. 

37. U.S. EPA. Benzene Emissions from Coke By-Product Recovery Plants—Background 
Information for Proposed Standards. EPA-450/3-83-016a. Research Triangle Park, 
North Carolina: U.S. Environmental Protection Agency, Office of Air Quality 

Planning and Standards, 1984. 

38. McCollum, H.R., J.W. Botkin, M.E. Hohman, and G.P. Huber. “Coke Plant Benzene 
By-Products NESHAP Operating Experience.” Presented at the 87th Annual Meeting 
and Exhibition of the Air and Waste Management Association. Cincinnati, Ohio: 

June 1994. 

39. U.S. EPA. Environmental Assessment of Coke By-Product Recovery Plants. 
EPA-600/2-79-016. Research Triangle Park, North Carolina: U.S. Environmental 
Protection Agency, 1979. 

40. Dufallo, J.M., D.C. Spence, and W.A. Schwartz. “Modified Litol Process for 

Benzene Production.” Chemical Engineering Progress. 77(l):56-62, 1981. 

41. Milton, H.E. By Carbonization. In: Toluene, the Xylenes and Their Industrial 
Derivatives. Hancock, E.G., ed. New York, New York: Elsevier Scientific 

Publishing Co., 1982. 

42. U.S. EPA. Coke Oven Emissions from Wet-Coal Charged By-Product Coke Oven 
Batteries-Background Information for Proposed Standards. Draft EIS. 
EPA-450/3-85-028a. Research Triangle Park, North Carolina: U.S. Environmental 
Protection Agency, Office of Air Quality Planning and Standards, April 1987. 

43. Coy, D. (Research Triangle Institute). Letter to G. Lacy (U.S. Environmental 
Protection Agency) concerning Benzene Emissions from Foundry Coke Plants. Docket 
No. A-79-16, Item FV-B-7. March 11, 1985. 

44. National Emissions Standards for Hazardous Air Pollutants; Benzene Emissions from 
Maleic Anhydride Plants, Ethylbenzene/Styrene Plants, Benzene Storage Vessels, 
Benzene Equipment Leaks, and Coke By-Product Recovery Plants; Final Rule. 

54 FR 38044-38082, September 14, 1989. 


10-4 



45. U.S. EPA. Control Techniques for Volatile Organic Compound Emissions from 

Stationary Sources. EPA-453/R-92-018. Research Triangle Park, North Carolina.' 
U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, 
December 1992. 


46. U.S. EPA. Reactor Processes in the Synthetic Organic Chemical Manufacturing 
Industry-Background Information for Proposed Standards. EPA-450/3-90-016a. 
Research Triangle Park, North Carolina: U.S. Environmental Protection Agency, 
Office of Air Quality Planning and Standards, June 1990. 


47. Schwartz, R.J., and C.J. Pereira (W.R. Grace & Co.). “Summary of Options for the 


Prmt-n 1 Ot- 


rganic Compounds from the Chemical Process Industry’. 


Presented at the 87th Annual Meeting and Exhibition of the Air and Water Management 
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185. AP-42, 5th ed., op. cit., reference 31. Section 11.2: “Asphalt Roofmg Manufacture,” 
1995. 

186. U.S. EPA. Asphalt Roofing Manufacturing Industry Background Information 
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187. Kelly, M.E. Sources and Emissions of Polycyclic Organic Matter. 

EPA-450/5-83-010b. Research Triangle Park, North Carolina: U.S. Environmental 
Protection Agency, 1983. pp. 5-62 to 5-67. 


10-17 


188. Gerstle, R.W. Atmospheric Emissions From Asphalt Roofing Processes. 
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189. U.S. EPA. Evaluation of VOC Emissions From Heated Roofing Asphalt. 

EPA-600/2-91-061. Research Triangle Park, North Carolina: U.S. Environmental 
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190. Siebert, P.C., et al. Preliminary Assessment of the Sources, Control and Population 
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U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, 
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191. U.S. EPA. Indoor Air Quality Data Base for Organic Compounds. PB92-158468. 
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Office of Research and Development, Air and Energy Engineering Research 
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192. Tichenor, B.A. Measurement of Organic Compound Emissions Using Small Test 
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193. U.S. EPA. Report to Congress: Volatile Organic Compound Emissions from 
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194. U.S. EPA. Locating and Estimating Air Toxic Emissions from Sources of Medical 
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195. AP-42, 5th ed., op. cit ., reference 31. Section 2.3: “Medical Waste Incineration,” 

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196. California Air Resources Board. Confidential Report No. ERC-53. 

197. AP-42, 5th ed., op. cit., reference 31. Section 2.2: “Sewage Sludge Incineration,” 

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198. U.S. EPA. Locating and Estimating Air Toxics Emissions from Sewage Sludge 
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April 30, 1989. 


10-18 


199. Vancil, M.A. et al. Emissions of Metals and Organics From Municipal Wastewater 
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200. Standards for the Use and Disposal of Sewage Sludge, 58 FR 9248-9415, 

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201. Oppelt, E.T. Incineration of Hazardous Waste--A Critical Review. Journal of Air 
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203. Mao, Z. and M.J. Mcintosh. “Incineration of Toluene and Chlorobenzene in a 
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204. U.S. Code of Federal Regulations. Title 40, Protection of the Environment, 

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205. U.S. Code of Federal Regulations. Title 40, Protection of the Environment, 

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206. U.S. EPA. Alternative Control Techniques Document-NOx Emissions from Utility 
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207. Shih, C.C. et al. Emissions Assessment of Conventional Stationary Combustion 
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i 

208. AP-42, 5th ed., op. cit. y reference 31. Section 1.1: “Bituminous and Subbituminous 
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10-19 


209. Sverdrup, G.M., et al. “Toxic Emissions from a Cyclone Burner Boiler with an ESP 
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210. Fangmeier, B.A. et al. “Hazardous Air Pollutant Emissions from Natural Gas-Fired 
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211. AP-42, 5th ed., op. cit., reference 31. Section 1.3: “Fuel Oil Combustion,” 1995. 

212. U. S. EP A. Background Information Document for Industrial Boilers. 
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213. U.S. EPA. ICCR Inventory Database Version 3.0 . Office of Air Quality Planning and 
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214. AP-42, 5th ed., op. cit., reference 31. Section 1.6: “Wood Waste Combustion in 
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215. U.S. EPA. Locating and Estimating Air Emissions from Sources of Dioxin and Furans. 
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216. California Air Resources Board. Confidential Report No. ERC-71. 

217. California Air Resources Board. Confidential Report No. ERC-70. 

218. Hubbard, A.J. Hazardous Air Emissions Potential from a Wood-Fired Furnace. . 
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219. Interpoll Laboratories, Inc. Test Results. February 26, 1991 State Air Emission 
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220. California Air Resources Board. Confidential Report No. ERC-47. 

221. AP-42, 5th ed., op. cit., reference 31. Section 1.10: “Residential Wood Stoves,” 

1995. 


10-20 



222. AP-42, 5th ed., op. cit., reference 31. Section 1.9: “Residential Fireplaces,”1995. 

223. Energy Information Administration. State Energy Data Report . DOE/EIA-0214(90). 
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224. McCrillis, R.C., and R.R. Watts. Analysis of Emissions from Residential Oil 
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225. Energy Information Administration. Fuel Oil and Kerosene Sales 1990. 
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226. Suprenant, N.F., R.R. Hall, K.T. McGregor, and A.S. Werner. Emissions Assessment 
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227. Meioer, K.5., ana R.C. McCnins. Comparison of Emissions and Organic Fingerprints 
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228. Travnor, G.W., M.G. Apte, and H.A. Sokol. Selected Organic Pollutant Emissions 
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229. U.S. EPA. Emissions Assessment of Conventional Stationary Combustion Systems , 

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230. Flagan, R.C. and J.H. Seinfeld. Fundamentals of Air Pollution Engineering. 
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231. AP-42, 5th ed., op. cit., reference 31. Section 3.4: “Large Stationary Diesel and All 
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232. AP-42, 5th ed., op. cit., reference 31. Section 3.3: “Gasoline and Diesel Industrial 
Engines,” 1995. 


10-21 


233. AP-42, 5th ed., op. cix ., reference 31. Section 3.2: “ Heavy Duty Natural Gas-Fired 
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234. North American Electric Reliability Council (NAERC). Electricity Supply and 
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235. AP-42, 5th ed., op. cit., reference 31. Section 3.1: “Stationary Gas Turbines for 
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236. U.S. EPA. Secondary Lead Smelting Background Information Document For Proposed 
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237. Roy F. Weston, Inc. Testing on Selected Sources at a Secondary Lead Smelter. 
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238. Roy F. Weston, Inc. Emission Test Report - HAP Emission Testing on Selected 
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U.S. Environmental Protection Agency, Emission Measurement Branch, 1993. 

pp. 3-38, 3-39, 3-51. 

239. Roy F. Weston, Inc. Emission Test Report - HAP Emission Testing on Selected 
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240. U.S. EPA. Secondary Lead Smelting Background Information Document For Proposed 
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241. U.S. EPA. Test Methods for Evaluating Solid Waste , 3rd ed., Report No. SW-846. 
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Emergency Response, November 1986. 

242. U.S. EPA. Electric Arc Furnaces in Ferrous Foundries - Background Information for 
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U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, 
March 1982. pp. 3-1 to 3-19. 


10-22 




243. Keller, P.A. (Radian Corporation). Teleconference with J. Maysilles 

(U.S. Environmental Protection Agency) concerning Information from Short Survey of 
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244. AP-42, 5th ed., op. cit., reference 31. Section 12.10: “Gray Iron Foundries,” 1995. 

245. Environmental Technology and Engineering Corporation. Report to Waupaca 
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246. Bevington, D. (Radian Corporation) and S. Mermall (Department of Natural 
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247. AP-42, 5th ed., op. cit., reference 31. Section 11.6: “Portland Cement Production,” 
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248. Pierson, T. (Research Triangle Institute). Memorandum to T. Lahre (Office of Air 
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Summary of Portland Cement MACT Data, April 25, 1994. 


249. U.S. EPA. Burning Tires for Fuel and Tire Pyrolysis: Air Implications. 

EPA-450/3-91-024. Research Triangle Park, North Carolina: U.S. Environmental 

Protection Agency, Control Technology Center, December 1991. p. 4-9. 


250. Kim, I. Incinerators and Cement Kilns Face Off. Chemical Engineering. 

101 (4):41 -45, April 1994. 

251. Energy and Environmental Research Corporation. Technical Support for Revision of 
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U.S. Environmental Protection Agency, Office of Solid Waste, May 17, 1994. 


252. AP-42, 5th ed., op. cit., reference 31. Section 11.1: “Hot Mix Asphalt Production,” 

1995. 


253. U.S. EP A. Second Review of New Source Performance Standards for Asphalt Concrete 
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U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, 
October 1985. 

254. Engineering Science, Inc. A Comprehensive Emission Inventory Report As Required 
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September 14, 1990. 


10-23 


255. U.S. EPA. Emission Test Report, Mathy Construction Company Plant If6, LaCrosse, 
Wisconsin. EMB File No. 91-ASP-ll. Research Triangle Park, North Carolina: 

U.S. Environmental Protection Agency, Emissions Measurements Branch, February 
1992. 

256. Gunkel, K. O'C. NAPA Stack Emissions Program, Interim Status Report. Baltimore, 
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257. Engineering Science, Inc. Report of AB2588 Air Pollution Source Testing at Industrial 
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258. California Air Resources Board. Confidential Report No. ERC-12. 

259. Eureka Laboratories, Inc. Compilation of Air Toxics Pollutant Emission Factors , 

Vol. II B: Technical Support Information, Asphalt Concrete Plants, 1991 Edition, 
Appendix F, Plant 53. Prepared for Central Valley Rock, Sand & Gravel Association. 
January 1991. 

260. Eureka Laboratories, Inc. Compilation of Air Toxics Pollutant Emission Factors , 

Vo] IT B* Technical Support Information Asphalt Concrete Plants. 1991 Edition. 
Appendix G, Plant 501. Prepared for Central Valley Rock, Sand & Gravel 
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261. U.S. EPA. Emission Test Report, Mathy Construction Company Plant #26, New 
Richmond, Wisconsin. EMB File No. 91-ASP-10. Research Triangle Park, North 
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262. California Air Resources Board. Confidential Report No. ERC-11. 

263. Eureka Laboratories, Inc. Compilation of Air Toxics Pollutant Emission Factors , 

Vol. II B: Technical Support Information, Asphalt Concrete Plants, 1991 Edition, 
Appendix E, Plant 50. Prepared for Central Valley Rock, Sand & Gravel Association, 
January 1991. 

264. Ward, D.E. and W.M. Hao. “Air Toxic Emissions from Burning of Biomass 
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265. U.S. EPA. Evaluation of Improvement of Puget Sound Toxic Air Contaminants 
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10-24 


266. Peterson, J. and Ward, D. An Inventory of Particulate Matter and Air Toxic Emissions 
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U.S. Department of Agriculture Forest Service, Pacific Northwest Research Station, 
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267. AP-42, 5th ed., op. cit., reference 31. Section 2.5: “Open Burning,” 1995. 

268. AP-42, 5th ed., op. cit., reference 31. Section 13.1: “Wildfires and Prescribed 
Burning,” 1995. 

269. Lemieux, P. and D.M. DeMarini. Mutagenicity of Emissions from the Simulated Open 
Burning of Scrap Rubber Tires. EPA-600/R-92-127, Washington, D.C.: 

U.S. Environmental Protection Agency, Office of Research and Development, 

July 1992. 

270. Cook, R. (Office of Mobile Sources, U.S. Environmental Protection Agency, Ann 
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271. U.S. EPA. Procedures for Emission Inventory Preparation Vol. IV: Mobile Sources. 
EPA-450/4-81-026d (Revised). Research Triangle Park, North Carolina: 

U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, 
1992. 

272. Rieger. P. and W. McMahon. Speciation and Reactivity Determination of Exhaust 
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Annual Meeting & Exhibition, Vancouver, British Columbia, June 16 to 21, 1991. 

273. Chang, T.Y., R.H. Hammerle, S.M. Japar, and I.T. Salmeen (Ford Motor Company). 
Alternative Transportation Fuels and Air Quality. Environmental Science and 
Technology. 25(7), 1991. 

274. U.S. EPA. Nonroad Engine and Vehicle Emission Study . 21A-2001. Washington, 
D.C.: U.S. Environmental Protection Agency, Office of Air and Radiation, 

November 1991. 

275. Ingalls, M.N. Emission Factors of Air Toxics. Report #08-3426-005. San Antonio, 
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276. Booz-Allen and Hamilton. Commercial Marine Vessel Contributions to Emission 
Inventories. Ann Arbor, Michigan: Office of Mobile Sources, U.S. Environmental 
Protection Agency. October 7, 1991. 


10-25 


277. FAA 1990 Census of U.S. Civil Aircraft. 

278. U.S. Department of Energy. Petroleum Supply Annual 1993. Washington, D.C.: 

U.S. Department of Energy, Energy Information Administration, 1994. 

279. Vigyan Inc. Estimation and Evaluation of Cancer Risks.Attributed to Air Pollution in 
Southwest Chicago. U.S. Environmental Protection Agency, Air and Radiation 
Division, April 1993. 

280. Memorandum from Rick Cook, U.S. Environmental Protection Agency, Office of 
Mobile Sources to Anne Pope, U.S. Environmental Protection Agency, Office of Air 
Quality and Planning and Standards. “Source Identification and Base Year 1990 
Emission Inventory Guidance for Mobile Source HAPs on the OAQPS List of 

40 Priority HAPs” June 11, 1997. 

281. U.S. Department of Transportation. Federal Aviation Administration Air Traffic 
Activity, Fiscal Year 1993. Washington, D.C.: Federal Aviation Administration, 
Office of Aviation Policy Plans and Management Analysis, 1994. 

282. California Air Resources Board. Confidential Report No. ERC-57. 

2bj. b.5. EPa. Screening Methods for Development of Air Toxics Emission Factors. 

EPA-450/4-91-021. Research Triangle Park, North Carolina: U.S. Environmental 

Protection Agency, Inventory Guidance and Evaluation Section, September 1991. 

284. U.S. EPA. Test Methods for Evaluating Solid Waste , 3rd ed., Report No. SW-846. 
Washington, D.C.: U.S. Environmental Protection Agency, Office of Solid Waste and 
Emergency Response, November 1986. 

285. U.S. Code of Federal Regulations. Title 40, Protection of the Environment, 

Part 60-Standards of Performance for New Stationary Sources, Appendix A—Test 
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286. Pau, J.C., J.E. Knoll, and M.R. Midgett. A Tedlar® Bag Sampling System for Toxic 
Organic Compounds in Source Emission Sampling and Analysis. Journal of Air and 
Waste Management Association. 41(8): 1095-1097, August 1991. 

287. Moody, T.K. (Radian Corporation) and J. Pau (U.S. Environmental Protection 
Agency). Written communication concerning Emissions Monitoring Systems 
Laboratory. June 6, 1988. 


10-26 



288. Entropy Environmentalists, Inc. Sampling and Analysis of Butadiene at a Synthetic 
Rubber Plant. EPA Contract No. 68-02-4442. Research Triangle Park, North 
Carolina: U.S. Environmental Protection Agency, Atmospheric Research and 
Exposure Assessment Laboratory, Quality Assurance Division, October 1988. pp. 3-5. 

289. U.S. EPA. Compendium of Methods for the Determination of Toxic Organic 
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Carolina: U.S. Environmental Protection Agency, Atmospheric Research and 
Exposure Assessment Laboratory, June 1988. 

290. U.S. Code of Federal Regulations, Title 40, Protection of the Environment, Part 86, 
Subpart B, Emission Regulations for 1977 and Later Model Year New Light-Duty 
Vehicles and New Light-Duty Trucks; Test Procedures. Washington, D.C.: 

U.S. Government Printing Office, 1993. 

291. Blackley, C. (Radian Corporation) and R. Zweidinger (U.S. Environmental Protection 
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292. Blackley, C. (Radian Corporation) and P. Gabele (U.S. Environmental Protection 
Agency). Teleconference concerning mobile sources testing. May 10, 1994. 

293. U.S. EPA. Butadiene Measurement Technology. EPA 460/3-88-005. Ann Arbor, 
Michigan: U.S. Environmental Protection Agency, Office of Mobile Source Air 
Pollution Control, 1988. pp. 1-23, Al-15, Bl-5, Cl-3. 

294. Lee, F.S., and D. Schuetzle. Sampling, Extraction, and Analysis of Polycyclic 
Aromatic Hydrocarbons from Internal Combustion Engines. In: Handbook of 
Polvcyclic Aromatic Hydrocarbons , A. Bjorseth, ed. New York, New York: Marcel 
Dekker, Inc., 1985. 

295. Siegl, W.D., et al. “Improved Emissions Speciation Methodology for Phase II of the 
Auto/Oil Air Quality Improvement Research Program-Hydrocarbon and Oxygenates.” 
Presented at the International Congress and Exposition, Detroit, Michigan. SAE 
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pp. 63-98. 

296. AP-42, op. cit., reference 31. Draft Section 12.2: “Coke Production,” 

January 1, 1995. 


10-27 











































3 



















































APPENDIX A 


SUMMARY OF EMISSION FACTORS 





















. 

















TABLE A 1 . SUMMARY OF EMISSION FACTORS 


00 

0 

re 

QS 


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Light Oil Storage Uncontrolled 0.012 Ib/ton (5.8 g/Mg) 

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TABLE A-1. COMTINUED 


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TABLE A-1. CONTINUED 


60 

C 


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TABLE A 1. CONTINUED 


cm 

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A-5 


(continued) 














TABLE A 1. CONTINUED 



OO 

c 


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60 

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5-01-005-16 Solid Waste Disposal - Fluidized Bed Incinerator Venturi/Impingement 4.0 x 10 -4 Ib/ton 

_ Fluidized Bed Incinerator _ Scrubbers _ (2.0 x 10 1 g/Mg) 












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. 







































APPENDIX B 


UNITED STATES PETROLEUM REFINERIES: LOCATION BY STATE 






















































































■ 







































TABLE B-l. UNITED STATES PETROLEUM REFINERIES: LOCATION BY STATE 


State 

Company 

Location 

ALABAMA 

Coastal Mobil Refining Co. 

Mobile Bay 

ALABAMA 

Gamxx Energy, Inc. 

Theodore 

ALABAMA 

Hunt Refining Co. 

Tuscaloosa 

ALABAMA 

Louisiana Land & Exploration Co. 

Sar aland 

ALASKA 

ARCO 

Kuparuk 

ALASKA 

ARCO 

Prudhoe Bay 

ALASKA 

Mapco Alaska Petroleum 

North Pole 

ALASKA 

Petro Star Inc. 

North Pole 

ALASKA 

Tesoro Petroleum Corp. 

Kenai 

ARIZONA 

Intermountain Refining Cl 

Fredonia 

ARIZONA 

Sunbelt Refining Co. 

Randolph 

ARKANSAS 

Berry Petroleum Co. 

Stevens 

ARKANSAS 

Cross Oil & Refining Co. Inc. 

Smackover 

ARKANSAS 

Lion Oil Co. 

El Dorado 

CALIFORNIA 

Anchor Refining Cl 

McKittrick 

n a t TrnDVT a 

« k. L k mc liwiL 1 vlvlll lui V_. . 

C' nrcnT"' 

s -. Ml J V 1 1 

CALIFORNIA 

Chemoil Refining Corp. 

Signal Hill 

CALIFORNIA 

Chevron USA Inc. 

El Segundo 

CALIFORNIA 

Chevron USA Inc. 

Richmond 

CALIFORNIA 

Conoco Inc. 

Santa Maria 

CALIFORNIA 

Edgington Oil Cl 

Long Beach 

_w_ 

CALIFORNIA 

Exxon Co. 

Benicia 

CALIFORNIA 

Fletcher Oil & Refining Co. 

Carson 

CALIFORNIA 

Golden West Refining Co. 

Santa Fe Springs 

CALIFORNIA 

Huntway Refining Co. 

Benicia 

CALIFORNIA 

Huntway Refining Co. 

Wilmington 

CALIFORNIA 

Kern Oil & Refining Co. 

Bakersfield 

CALIFORNIA 

Lunday-Thagard Co. 

South Gate 

CALIFORNIA 

Mobil Oil Corp. 

Torrance 

CALIFORNIA 

-.—-- 

Pacific Refining Co. 

Hercules 

CALIFORNIA 

Paramount Petroleum Corp. 

Paramount 

CALIFORNIA 

Powerine Oil Co. 

Santa Fe Springs 

CALIFORNIA 

San Joaquin Refining Cl 

Bakersfield 

CALIFORNIA 

Shell Oil Co. 

Martinez 

CALIFORNIA 

Shell Oil Co. 

Wilmington ('Carson') 

CALIFORNIA 

Sunland Refining Corp. 

Bakersfield 


B-l 



































































TABLE B-l. UNITED STATE PETROLEUM REFINERIES: LOCATION BY STATE 

(CONTINUED) 


State 

Company 

Location 

CALIFORNIA 

Ten By, Inc. 

Oxnard 

CALIFORNIA 

Texaco Refining & Marketing Inc. 

Bakersfield 

CALIFORNIA 

Texaco Refining & Marketing Inc. 

Wilmington 

CALIFORNIA 

Tosco Corp. 

Martinez 

CALIFORNIA 

Ultramar 

Wilmington 

CALIFORNIA 

Unocal Corp. 

Los Angeles 

CALIFORNIA 

L T ncea! Corp. 

San Francisco 

(includes Santa Maria) 

CALIFORNIA 

Witco Chemical Corp, Golden Bear Div. 

Oildale 

COLORADO 

Colorado Refining Co. 

Commerce City 

COLORADO 

Conoco Inc. 

Denver 

COLORADO 

Landmark Petroleum Inc. 

Fruita 

DELAWARE 

Star Enterprise 

Delaware City 

—-—-—i 

GEORGIA 

Amoco Oil Co. 

Savannah 

GEORGIA 

Young Refining Corp. 

Douglasville 

HAW AH 

Chevron USA Inc. 

Barber's Point 

---- 

HAW AH 

Hawaiian Independent Refinery Inc. 

Ewa Beach 

ILLINOIS 

Clark Oil & Refining Corp. 

Blue Island 

ILLINOIS 

Clark Oil & Refining Corp. 

Hartford 

ILLINOIS 

Indian Refining Co. 

Lawrenceville 

ILLINOIS 

Marathon Oil Co. 

Robinson 

ILLINOIS 

Mobil Oil Corp. 

Joliet 

ILLINOIS 

Shell Oil Co. 

Wood River 

ILLINOIS 

The UNO-VEN Co. 

Lemont 

INDIANA 

Amoco Oil Co. 

Whiting 

_1C-- - 

INDIANA 

! Countrymark Cooperative, Inc. 

Mt. Vernon 

INDIANA 

-1- - 

Laketon Refining Corp. 

i 

Laketon 

INDIANA 

1 1 

Marathon Oil Co. 

Indianapolis 

KANSAS 

Coastal Refining and Marketing Inc. 

Augusta 

KANSAS 

Coastal Refining & Marketing Inc. 

El Dorado 

KANSAS 

Coastal Refining & Marketing Inc. 

Wichita 

KANSAS 

Farmland Industries Inc. 

Coffeyville 

KANSAS 

Farmland Industries Inc. 

Phillipsburg 

KANSAS 

National Cooperative Refinery Association 

McPherson 

KANSAS 

i Texaco Refining & Marketing Inc. 

i El Dorado 


B-2 































































































TABLE B-l. UNITED STATE PETROLEUM REFINERIES: LOCATION BY STATE 

(CONTINUED) 


State 

Company 

Location 

KANSAS 

Total Petroleum Inc. 

Arkansas City 

KENTUCKY 

Ashland Petroleum Co. 

Catlettsburg 

KENTUCKY 

Somerset Refinery Inc. 

Somerset 

LOUISIANA 

American International Refining, Inc. 

Lake Charles 

LOUISIANA 

Atlas Processing Co. Div. of Pennzoil 

Shreveport 

LOUISIANA 

BP Oil Co. 

Belle Chasse 

LOUISIANA 

Calcasieu Refining Co. 

Lake Charles 

LOUISIANA 

Calumet Lubricants Co. 

Princeton 

LOUISIANA 

Canal Refining Co. 

Church Point 

LOUISIANA 

CAS Refining, Inc. 

Mermentau 

LOUISIANA 

Citgo Petroleum Corp. 

Lake Charles 

LOUISIANA 

Conoco Inc. 

Lake Charles 

LOUISIANA 

Exxon Co. 

Baton Rouge 

LOUISIANA 

Kerr McGee Refining Corp. 

Cotton Valley 

LOUISIANA 

Marathon Oil Co. 

Garvville 

LOUISIANA i Mobil Oil Corp. 

Chalmette 

LOUIS ANA Murphy Oil USA Inc. 

* 

Meraux 

LOUISIANA Phibro Refining Inc. 

Krotz Springs 

LOUISIANA Phibro Refining Inc. 

St. Rose 

LOUIS ANA Placid Refining Co. 

Port Allen 

LOUISIANA Shell Oil Co. ! Norco 

LOUISIANA Star Enterprise 

Convent 

MICHIGAN i Crystal Refining Co. 

Carson City 

MICHIGAN 

Lakeside Refining Co. 

Kalamazoo 

MICHIGAN 

Marathon Oil Co. 

Detroit 

MICHIGAN 

Total Petroleum Inc. 

Alma 

MINNESOTA 

Ashland Petroleum Co. 

St. Paul Park 

MINNESOTA 

Koch Refining Co. 

Rosemount 

MISSISSIPPI 

Amerada-Hess Corp. 

Purvis 

MISSISSIPPI 

Chevron USA Inc. 

Pascagoula 

MISSISSIPPI 

Ergon Refining Inc. 

Vicksburg 

MISSISSIPPI 

Southland Oil Co. 

Lumberton 

MISSISSIPPI 

Southland Oil Co. 

Sandersville 

MONTANA 

Cenex 

Laurel 

MONTANA 

Conoco Inc. 1 Billings 


B-3 




























































TABLE B-l. UNITED STATE PETROLEUM REFINERIES: LOCATION BY STATE 

(CONTINUED) 


State 

Company 

Location 

MONTANA 

Exxon Co. 

Billings 

MONTANA 

Montana Refining Co. 

Great Falls 

NEVADA 

Petro Source Refining Partners 

Tonopah 

NEW JERSEY 

Amerada-Hess Corp. 

Port Reading 

NEW JERSEY 

Chevron USA Inc. 

Perth Amboy 

NEW JERSEY 1 

Coastal Eagle Point Oil Co. 

Westville 

NEW JERSEY 

Exxon Co. 

Linden 

NEW JERSEY 

Mobil Oil Corp. 

Paulsboro 

NEW JERSEY 

Seaview Petroleum Co. LP 

Thorofare 

NEW MEXICO 

Bloomfield Refining Co. 

Bloomfield 

NEW MEXICO 

Giant Industries Inc. 

Gallup 

NEW MEXICO 

Navajo Refining Co. 

Artesia 

NEW MEXICO 

Triftway Marketing Corp. 

Farmington 

NEW YORK 

Cibro Petroleum Products Co. 

Albany 

NORTH DAKOTA 

—-———- 1 

Amoco Oil Co. 

Mandan 

OHIO i Ashland Petroleum Co. 

Canton 

OHIO 1 BP Oil Co. 

Lima 

OHIO BP Oil Co. 

Toledo 

OHIO Sun Refining & Marketing Co. 

Toledo 

OKLAHOMA Barrett Refining Corp. 

Thomas 

OKLAHOMA Conoco Inc. 

Ponca City 

OKLAHOMA Cyril Petrochemical Corp. 

Cyril 

OKLAHOMA Kerr-McGee Refining Corp. 

Wynnewood 

OKLAHOMA 

Sinclair Oil Corp. 

Tulsa 

OKLAHOMA Sun Refining & Marketing Co. 

Tulsa 

OKLAHOMA Total Petroleum Inc. 

Ardmore 

OREGON 

Chevron USA Inc. 

Portland 

PENNSYLVANIA 

BP Oil Co. 

Marcus Hook 

PENNSYLVANIA 

! Chevron USA Inc. 

Philadelphia 

PENNSYLVANIA 

Pennzoil Products Co. 

Rouseville 

PENNSYLVANIA 

Sun Refining & Marketing Co. 

Marcus Hook 

PENNSYLVANIA 

Sun Refining & Marketing Co. 

Philadelphia 

PENNSYLVANIA 

United Refining Co. 

Warren 

PENNSYLVANIA 

Witco Chemical Co., Kendall-Amalie Div. 

Bradford 

TENNESSEE 

1 Mapco Petroleum Inc. 

| Memphis 


B-4 






































































TABLE B-l. UNITED STATE PETROLEUM REFINERIES: LOCATION BY STATE 

(CONTINUED) 


State 

Company 

Location 

TEXAS 

Amoco Oil Co. 

Texas City 

TEXAS 

Chevron USA Inc. 

El Paso 

TEXAS 

Chevron USA Inc. 

Port Arthur 

TEXAS 

Citgo 

Corpus Christi 

TEXAS 

Coastal Refining & Marketing Inc. 

Corpus Christi 

TEXAS 

Crown Central Petroleum Corp. 

Houston 

TEXAS 

Diamond Shamrock Corp. 

Sunray 

TEXAS 

Diamond Shamrock Corp. 

Three Rivers 

TEXAS 

El Paso Refining CL 

El Paso 

TEXAS 

Exxon Co. USA 

Baytown 

TEXAS 

Fina Oil & Chemical Co. 

Big Spring 

TEXAS 

Fina Oil & Chemical Co. 

Port Arthur 

TEXAS 

Howell Hvdrocarbons Inc. 

San Antonio 

TEXAS 

Koch Refining Co. 

Corpus Christi 

TEXAS 

LaGloria Oil & Gas Co. 

Tvler 

TEXAS 

Leal Petroleum Corp. 

Nixon 

TEXAS 

Liquid Energy Corp. 

Bridgeport 

TEXAS 

Lyondell Petrochemical Co. 

Houston 

TEXAS 

Marathon Oil Co. 

Texas City 

TEXAS 

Mobil Oil Corp. 

Beaumont 

TEXAS 

Phibro Refining Inc. 

Houston 

TEXAS 

Phibro Refining Inc. 

Texas City 

_ d. - 

TEXAS 

Phillips 66 Co. 

Borger 

TEXAS 

Phillips 66 Co. 

Sweeny 

TEXAS 

Pride Refining Inc. 

Abilene 

TEXAS 

Shell Oil Co. 

Deer Park 

TEXAS 

Shell Oil Co. 

Odessa 

TEXAS 

Southwestern Refining Co., Inc. 

Corpus Christi 

TEXAS 

Star Enterprise 

Port Arthur 

TEXAS 

Trifinery 

Corpus Christi 

TEXAS 

Valero Refining Co. 

Corpus Christi 

UTAH 

Amoco Oil Co. 

Salt Lake City 

UTAH 

Big West Oil Co. 

Salt Lake City 

UTAH 

Chevron USA 

Salt Lake City 

UTAH 

Crysen Refining Inc. 

Woods Cross 


B-5 























































TABLE B-l. UNITED STATE PETROLEUM REFINERIES: LOCATION BY STATE 

(CONTINUED) . 


State 

Company 

Location 

UTAH 

Pennzoil Products Co. 

Roosevelt 

UTAH 

Phillips 66 Co. 

Woods Cross 

VIRGINIA 

Amoco Oil Co. 

Yorktown 

WASHINGTON 

Atlantic Richfield Co. 

Femdale 

WASHINGTON 

BP Oil Co. 

Femdale 

WASHINGTON 

Chevron USA Inc. 

Seattle 

WASHINGTON 

Shell Oil Co. 

Anacortes 

WASHINGTON 

Sound Refining Inc. 

Tacoma 

WASHINGTON 

Texaco Refining & Marketing Inc. 

Anacortes 

WASHINGTON 

U.S. Oil & Refining Co. 

Tacoma 

WEST VIRGINIA 

Phoenix Refining Co. 

St. Mary’s 

___ m. - 

WEST VIRGINIA 

Ouaker State Oil Refining Corp. 

Newell 

WISCONSIN 

Murphy Oil USA Inc. 

Superior 

WYOMING 

1 Frontier Oil & Refining Co. 

Cheyenne 

WYOMING 

Little America Refining Co. 

Casper 

WYOMING 

Sinclair Oil Corp. 

Sinclair 

WYOMING 

’ Wyoming Refining Co. 

' —w--—-- ■ — 

Newcastle 


Source: 1/1/92 issue of Oil and Gas Journal 









































—- -- 

TECHNICAL REPORT DATA 

(PLEASE READ INSTRUCTIONS ON THE REVERSE BEFORE COMPLETING) 

REPORT NO. 2. 

EPA-454/R-98-011 

3. RECIPIENT'S ACCESSION NO. 

TITLE AND SUBTITLE 

LOCATING AND ESTIMATING AIR EMISSION FROM SOURCES OF 
BENZENE 

5. REPORT DATE 

6/1/98 

6. PERFORMING ORGANIZATION CODE 

AUTHOR(S) 

8. PERFORMING ORGANIZATION REPORT NO. 

PERFORMING ORGANIZATION NAME AND ADDRESS 

EASTERN RESEARCH GROUP, INC 

POBOX 2010 

MORRISVILLE, NC 27560 

10. PROGRAM ELEMENT NO. 

11. CONTRACT/GRANT NO. 

68-D7-0068 

. SPONSORING AGENCY NAME AND ADDRESS 

U. S. ENVIRONMENTAL PROTECTION AGENCY 

OFFICE OF AIR QUALITY PLANNING AND STANDARDS (MD-14) 

RESEARCH TRIANGLE PARK, NC 27711 

13. TYPE OF REPORT AND PERIOD COVERED 

FINAL 

14. SPONSORING AGENCY CODE 


SUPPLEMENTARY NOTES 

EPA WORK ASSINGMENT MANAGER: DENNIS BEAUREGARD (919) 541-5512 


ABSTRACT 

TO ASSIST GROUPS INTERESTED IN INVENTORYING AIR EMISSIONS OF VARIOUS POTENTIALLY TOXIC 
SUBSTANCES, THE U.S. ENVIRONMENTAL PROTECTION AGENCY IS PREPARING A SERIES OF 
DOCUMENTS, SUCH AS THIS, TO COMPILE AVAILABLE INFORMATION ON SOURCES AND EMISSIONS OF 
THESE SUBSTANCES. THIS DOCUMENT DEALS SPECIFICALLY WITH BENZENE. ITS INTENDED AUDIENCE 
INCLUDES, FEDERAL, STATE, AND LOCAL AIR POLLUTION PERSONNEL AND OTHERS INTERESTED IN 
LOCATING POTENTIAL EMITTERS OF BENZENE AND IN MAKING GROSS ESTIMATES OF AIR EMISSIONS 
THEREFROM. 

THIS DOCUMENT PRESENTS INFORMATION ON (1) THE TYPES OF SOURCES THAT MAY EMIT BENZENE; (2) 
PROCESS VARIATIONS AND RELEASE POINTS FOR THESE SOURCES; AND (3) AVAILABLE EMISSIONS 
INFORMATION INDICATING THE POTENTIAL FOR BENZENE RELEASES INTO THE AIR FROM EACH 
OPERATION. 


KEY WORDS AND DOCUMENT ANALYSIS 


DESCRIPTORS 

BENZENE 

AIR EMISSION SOURCES 

TOXIC SUBSTANCES 

EMISSION ESTIMATION 

b. IDENTIFIERS/OPEN ENDED TERMS 

c. COSAT1 FIELD/GROUP 

DISTRIBUTION STATEMENT 

UNLIMITED 

UNCLASSIFIED 

21. NO. OF PAGES 

574 

UNCLASSIFIED 

22. PRICE 






















































































































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